IR 05000400/1996001
| ML18012A192 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 03/08/1996 |
| From: | Darrell Roberts, Shymlock M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18012A189 | List: |
| References | |
| 50-400-96-01, 50-400-96-1, NUDOCS 9603270233 | |
| Download: ML18012A192 (52) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETlA STREET, N.W., SUITE 2900 ATLANTA,GEORGIA 303234199 Report No.: 50-400/96-01 Licensee:
Carolina Power 3 Light Company P. 0.
Box 1551 Raleigh, NC 27602 Docket No.: 50-400 Facility Name:
Harris Unit
Inspection Conducted:
January 7 - February 10, 1996 Inspector:
License No.:
NPF-63 o erts, ct1ng Sen>or es)
ent nspector a
e lgne J. Blake, Senior Project Hanager, paragraphs 3. 1, 3.4, 5, 17 R. Carrion, Radiation Specialist, paragraphs 5. 1 - 5. 10, 5.20 R.
Chou, Reactor Inspector, paragraphs 4. 1 - 4.7, 4.9 - 4. 10 J.
Lenahan, Reactor Inspector, paragraphs 4. 1 - 4.7, 4.9 - 4. 10 W. Rankin, Senior Project Hanager, paragraphs 5. 11 5.20 Approved by:
ym oc
,
C se
~g Reactor Projects Branch
Division of Reactor Projects SUMMARY Scope:
Inspections were conducted by the resident and/or regional inspectors in the areas of plant operations which included reviews of shift logs and facility records, conduct of plant tours (including backshift),
event follow-up, overtime review, and LfR review; maintenance which included maintenance and surveillance observations, and LfR review; engineering which included reviews of design change control processes, engineering backlog, design change packages, engineering response to emergent issues, and licensee inspections of safety-related water control structures; and plant support which included reviews of the radiological effluents and chemistry programs; review of control room emergency ventilation system, radwaste volume reduction program, and radioactive material transportation; review of contamination control and ALARA programs; reviews of plant housekeeping, security and fire protection program implementation; and a review of an emergency declaration from December 1995.
Enclosure
9603270233 960308 PDR ADOCK 05000400
Results:
Plant 0 erations One violation was identified by the inspector for inadequate corrective actions in controlling RA8 emergency ventilation boundary doors (paragraph 2.4).
A cold weather spell caused two refueling water storage tank level channels to become inoperable, requiring plant entry into Technical Specification 3.0.3 (paragraph 2.5).
An unresolved item was opened concerning
a possible Technical Specification violation involving an inoperable refueling water storage tank level instrument channel being placed in service (paragraph 2.6).
Inattention to detail was noted by the inspector in initiating caution tags for control board switches, (paragraph 2.2).
Operators'vertime usage was found to be in compliance with Technical Specifications.
Recent operations procedure deficiencies (including those identified in Operations Surveillance Tests)
have indicated a potential negative trend in that area (paragraph 2.8).
Plant management has developed a program designed to more effectively use management in the field (paragraph 2.3).
Overall, plant operations were conducted satisfactorily.
Maintenance Maintenance and surveillance activities observed by the inspectors were performed well.
One slave relay test procedure (performed in December 1995 but documented in a Licensee Event Report during this period) resulted in the unexpected opening of a reactor trip breaker while the plant was already shutdown (paragraph 3.3. 1).
Related to that event,. test procedure deficiencies and personnel errors were identified and corrected by the licensee.
Another licensee-identified violation was noted involving a surveillance procedure.
This Non-Cited Violation involved a procedural deficiency that was more than a year old, but identified during recent licensee activities (paragraphs 3.3.2)
~
The licensee is currently implementing a Technical Specification Surveillance Review project (which was developed prior to but in accordance with NRC Generic Letter 96-01, Testing of Safety-Related Logic Circuits) to further identify and correct other potential logic testing deficiencies (paragraph 3.3. 1).
A Nuclear Assessment Section maintenance audit was thorough in identifying recent maintenance performance trends (paragraph 3.4).
En ineerin The licensee was effectively managing engineering backlog (paragraph 4.2).
Engineering self assessments were effective in providing useful oversight to plant management (paragraph 4.6).
Engineering response to emergent issues was good (paragraph 4.7).
Design packages and calculations were thorough (paragraphs 4.3 and 4,4).
One design package (Plant Change Request 6502)
associated with Auxiliary Feedwater flow control valves resulted in numerous testing deficiencies identified by the licensee.
The licensee is currently implementing corrective actions for those items (paragraph 4.6).
The West Auxiliary Dam and the separating dike were in good condition (paragraph 4.5).
One licensee-identified Non-Cited Violation was noted for failure to perform response time testing for AFW flow control valves (paragraph 4.8).
Plant Su ort All programs reviewed, including radioactive effluents and water chemistry, ALARA, contamination control, security, and fire protection, were adequately implemented.
As a possible result of water chemistry programs, the Harris steam generators are performing well (paragraph 5.3.3).
Sludge lancing and early boration efforts have been effective (paragraphs 5.3.2 and 5.2.2).
Radwaste volume reduction efforts have been effective (paragraph 5.8).
Radioactive material shipments were well performed (paragraph 5.9).
The licensee's Control Room Emergency Ventilation System was well-maintained and Technical Specification-required surveillances satisfied their respective acceptance criteria (paragraph 5.7).
The licensee had taken a proactive position in the development of contingency plans to assure adequate on-site low level radwaste storage (paragraph 5. 10).
Corrective actions to self assessment findings in the plant support area were good (paragraph 5.15).
Hinor examples of poor radiological practices were noted as isolated occurrences (paragraphs 5. 12 and 5. 13).
A Non-Cited Violation was issued for untimely Notice of Unusual Event declaration following a train derailment on plant property (paragraph 5. 16).
REPORT DETAILS Acronyms used in this report are defined in paragraph 9.
1.0 PERSONS CONTACTED 2.0 2.1 Licensee Employees
- Alexander, D., Supervisor, Licensing and Regulatory Programs Batton, D., Superintendent, On-Line Scheduling Braund, D., Superintendent, Security
- Collins, J.,
Manager, Training
- Dobbs, J.,
Hanager, Outage and Scheduling
- Donahue, J.,
General Manager, Harris Plant Duncan, R., Superintendent, Mechanical Systems
- Gautier, W., Manager, Maintenance Hamby, H., Supervisor, Regulatory Compliance
- Hill, H., Manager, Nuclear Assessment HcCarthy, D., Superintendent, Outage Management
- Robinson, W., Vice President, Harris Plant
- Rolfson, G., Manager, Harris Engineering Support Services Sewell, S., Superintendent, Design Control
- Walt, T., Manager, Performance Evaluation and Regulatory Affairs White, B., Manager, Environmental and Radiation Control
- Williams, A., Hanager, Operations Other licensee employees contacted included office, operations, engineering, maintenance, chemistry/radiation control, and corporate personnel.
PLANT OPERATIONS (71707, 92700, 92901)
Plant Status 2.2 The plant was essentially at full power throughout the inspection period.
The unit ended the period in day 41 of power operation since startup on January 1,
1996.
Shift Logs and Facility Records The inspector reviewed records and discussed various entries with operations personnel to verify compliance with the TS and the licensee's administrative procedures.
In addition, the inspector independently verified clearance order tagouts.
Logs were legible and well organized, and provided sufficient information on plant status and events.
Clearance tagouts reviewed were properly implemented.
The inspector noted on one occasion that caution tags for three AFW valves and one ESW valve appeared on the main control board but not on corresponding switches at the auxiliary control panel.
On another occasion, a valve stroke limitation (no more than one valve stroke in 10 minutes)
had been imposed by the vendor for the main feedwater isolation valves but not included in a permanent plant procedure or on caution tags at the valve control switches.
Instead,
the information was referenced on a note pad on the balance-of-plant operator's desk in the control room.
These items were immediately corrected when brought to the operators'ttention.
Caution tags were generated for the auxiliary control panel (AFW and ESW valves)
and the main control board (FWIVs).
The inspector considered these to be examples of inattention to detail regarding equipment control.
Operators generated CRs for each case.
Aside from these examples, shift logs and facility records were adequate.
The inspectors identified no violations or deviations in this area.
2.3 2.4 Facility Tours and Observations Throughout the inspection period, the inspectors toured the facility to observe activities in progress, and attended morning status meetings to observe planning and management activities.
The tours included monitoring instrumentation and equipment operation, verification that operating shift staffing met TS requirements, and that the licensee was conducting control room operations in an orderly and professional manner.
The inspectors additionally observed several shift turnovers to verify continuity of plant status, operational problems, and other pertinent plant information.
During the shift turnovers and meetings, plant personnel.clearly communicated important plant status changes, weather related problems, and other deficiencies.
Recent discussions with plant management and inspector field observations indicated that management presence in the field could be improved.
Plant management has implemented a Plant Hanagement Observation Program (PHOP) designed to increase the amount and effectiveness of management field presence.
Overall, licensee performance observed during facility tours and observations was satisfactory.
Auxiliary Building Emergency Ventilation System Inoperability During a plant tour on January 10, 1996, the inspector found reactor auxiliary building emergency exhaust system (RABEES) boundary door 591 blocked open with a clear plastic wall clock cover.
The door, which accesses the north-end mechanical penetration area of the RAB from the primary system sample room, was fully open with no one apparently controlling it.
The inspector phoned control room personnel who indicated they were unaware of the door's status and immediately dispatched an auxiliary operator to close it.
The door provided a
boundary between rooms served by the normal ventilation system and those served by RABEES.
The door's closure was required for RABEES operability.
In accordance with TS 3/4.7.7, to be considered operable, RABEES is required to maintain affected rooms at a negative pressure of I/8" water gauge with respect to atmosphere.
Both trains of RABEES serve each affected room.
With the door blocked open on January 10, both trains of RABEES were considered inoperable until an auxiliary operator was dispatched to close it.
Control room operators appropriately entered TS 3.0.3 and initiated a
CR for further review.
Engineering tests later confirmed that the emergency ventilation system could not have maintained the mechanical penetration area at the
required negative pressure.
The TS 3.0.3 was exited before a plant shutdown was required.
The RABEES system is described in FSAR Section 6. 1.
The RABEES system fans (one per train) automatically start on a safety injection signal, and, unlike the normal exhaust system, have demisters and heaters which are provided to reduce the relative humidity of inlet air for charcoal adsorber protection.
Medium efficiency filters and HEPA filters are also provided for each fan (E6-A and E6-B).
The system's primary function is to maintain the post-accident radiological releases within the guidelines of 10 CFR 100 following a postulated long term passive failure in the containment sump water recirculation system.
The system filters airborne leakage from such passive failures which may be a
source of additional offsite dose.
The RABEES system is powered from an emergency power source, and during the design basis accident is sequenced onto the emergency bus via the LOCA sequencer.
Dampers isolating rooms served by RABEES automatically close on the same sequencer program that starts the fans.
Each damper's position is detected by limit switches which provide indication in the main control room.
No such indication or alarms currently exist for doors accessing the same RABEES rooms.
Over the years, the licensee has experienced recurring problems with controlling the RABEES ventilation boundaries.
In 1990, a damper failure resulted in the system being inoperable, and further investigation indicated that doors serving RABEES rooms had been routinely blocked open for maintenance activities without any licensee controls (LER 400/90-10).
Consequently, administrative controls were developed (administrative procedure AP-002, Conduct of Operations)
and implemented to provide better control over the boundary doors.
The licensee has since taken credit for these administrative controls which allow the doors to be blocked open provided the control room shift supervisor is notified and the responsible party can close the door within 10 minutes of a "Reactor Trip" announcement.
RABEES doors (25 total) were identified in the plant with yellow"diagonal stripes painted across a green background.
Signs are also posted reminding personnel of the policy to notify the shift supervisor before blocking the doors open.
Operators currently make log entries denoting any doors that are open, 'the time they were opened, and the name of the person responsible for closing them.
In the past year, the inspector has identified two situations where the doors were blocked open without control room approval or knowledge:
the latest on January 10 and one in April 1995 for which Violation 400/95-08-01 was issued.
The licensee has documented two additional incidents of inadequate RABEES door control:
one also in April 1995, and one in November 1995 when a door was damaged and would not fully close after transporting a, cart through it.
For the November 1995 event, corrective actions included fixing the door and counseling a control room SCO who made assumptions concerning RABEES operability without consulting engineerin.5 In the first three events above (the two in April and one in November 1995),
the doors were determined not to be opened sufficiently to prevent the system from maintaining the rooms at the required negative pressure.
This was supported by system testing and/or previous engineering evaluations.
As stated earlier, the latest incident in January resulted in the system being inoperable requiring entry into TS 3.0.3.
Licensee personnel initiated a root cause investigation into this event.
Plant management questioned all personnel who had access to the area (as, indicated by vital area security logs).'he door was last verified closed at approximately 8:00 that morning by an AO on daily rounds.
The inspector found it blocked open at 10:25 a.m.
The only people that were aware of the door's opening during that time were the AO who had been dispatched to close it, and a chemistry technician who normally obtains grab samples in the adjacent primary system sample room.
The technician indicated that he noticed the door was blocked open at approximately 8:45 a.m.,
but assumed that the main control room was aware of it.
He assumed that personnel painting in nearby areas of the RAB were responsible for the door.
The licensee determined that the cause of the door being blocked open was inconclusive, but that the clock face cover (found blocking the door open)
had probably fallen to the ground accidentally, and that someone passing through the door inadvertently caused it to be wedged open without verifying that it shut behind them.
The inspector concluded that previous corrective actions (counseling individuals, repairing specific doors)
and administrative controls were inadequate to prevent recurring problems with controlling RABEES doors.
CFR 50, Appendix B, Criterion 16 and the licensee's Corporate guality Assurance Program Manual, Revision 18, required that measures be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected.
In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.
The inspector concluded that the recurrence of adverse conditions related to controlling RABEES boundary doors was significant and that previous corrective actions did not meet the above requirements.
This is identified as Violation 400/96-01-01:
Inadequate Corrective Actions for Improper Control of RABEES Doors.
As an interim corrective action, all plant personnel were required to sign a statement acknowledging their knowledge of administrative requirements for the RABEES doors.
At the end of the inspection period, licensee personnel were evaluating further corrective actions for the RABEES door problems.
Cold Weather Affects RWST Level Channels During the weekend of February.
2 through February 5,
1996, arctic weather conditions occurred at the Harris plant.
Some plant equipment suffered from the extreme cold (temperatures below 10 degrees with sub-zero wind chill conditions)
causing several unexpected control room
alarms and unanticipated instrument indication changes.
Affected items included the main turbine's load drop anticipator function, the meteorological tower, a normal service water strainer backflush function, and several eye wash stations that were frozen.
These and other weather-related items were documented in control room logs and tracked for corrective actions.
Operators initiated prompt corrective actions to restore the equipment to within normal operating parameters.
Some equipment required more extensive maintenance or engineering involvement to fix or resolve.
At approximately 3:30 a.m.
on February 5, control room operators received a
RWST High Level alarm due to RWST level instrument LI-0991 (Channel 2) failing high.
The associated RWST level channel is one of four designed to function during the recirculation phase following a LOCA.
The level channels provide input to a two-out-of-four protection logic allowing RHR and Containment Spray pump suction swapover to the containment sump (on low-low RWST water level coincident with a safety injection signal).
As allowed by TS 3.3.2.b.2, Table 3.3-3, Action Statement 16, with one less than the total number of channels operable, operators appropriately placed LT-0991 in bypass using procedure OWP-ESF-05, Engineered Safety Features Actuation, then proceeded with normal plant operations.
The level transmitters for each channel are provided locally at the RWST which itself is open to the environment (except for four seismic walls surrounding it).
Operators determined that the channel failure was caused by cold weather freezing the sensing lines for level transmitter LT-0991.
A small space heater was immediately placed near the instrument sensing lines for LT-0991, but this was ineffective.
Approximately five hours later, level instrument LI-0990 (Channel 1)
also failed high.
Plant personnel determined that the second channel's failure was also due to frozen sensing lines for the locally mounted transmitter.
Since the TS only allowed the additional channel to be bypassed for two hours to do surveillance testing, operators appropriately entered TS 3.0.3 and initiated corrective actions for both failed channels.
Immediate corrective actions included using heat guns and then placing larger capacity heaters near the individual transmitter sensing lines and trending tank area temperatures.
The sensing lines were warmed and RWST level indications in the control room returned to normal for both affected channels.
After lengthy discussions with licensee engineering staff and a satisfactory channel check, operators declared level channel 1 operable and exited TS 3.0.3 within three hours.
The bases for the operability determination was appropriately documented in control room logs.
The cause for the instrument failures was determined to be wet sensing line insulation combined with the sub-freezing temperatures experienced over a three to four day period.
Each level transmitter's sensing lines are heat traced and insulated, and the transmitters themselves are located inside box-shaped enclosures covered with thin metal lagging.
Heavy rain/sleet had occurred days earlier causing ground water accumulation in the RWST pit (where the transmitters are located).
Either the rain itself or the standing level of water (which is generally pumped to a collection sump at operator discretion)
came in contact with the insulation.
The lines eventually froze and resultant water density changes caused indication for the two channels to fail high.
Heating the lines and subsequent testing restored operability and addressed the current cold spell.
During discussions with licensee personnel and a review of the maintenance history for the transmitters, the inspector determined that weather-related failures had occurred in the past for the RWST level channels.
The licensee's corrective actions had included enhancing operator rounds to specifically check heat trace panels associated with these lines, and re-routing sensing lines to make them less accessible to ground water.
Preparations for the recent cold spell included placing heat lamps by the four transmitters to prevent freezing.
These actions were obviously ineffective, and licensee management initiated a
root cause investigation to address deficiencies surrounding cold weather protection for the RWST level channels.
The inspector shared the licensee's concern with recurring weather-related problems for these transmitters and will track the licensee's corrective actions with the LER for this event due in March 1996.
2.6 Inoperable RWST Level Channel Inappropriately Returned to Service After declaring the second RWST level transmitter operable on February 5, operators determined that the first level transmitter should remain inoperable until a channel calibration could be performed.
This determination was based on the fact that when the instrument failed high and was subsequently bypassed, operations could not ascertain whether or not its transmitter had been over-ranged.
As mentioned above, operators used procedure OWP-ESF-05 on February 5 to bypass the inoperable channel as required by TS.
Bypassing an inoperable channel prevents any erroneous indications from tripping the channel and causing inadvertent actuations.
After any one channel is bypassed, the logic is reduced to a two-out-of-three channels for RHR and containment spray pump suction swapover to the containment sump.
At approximately 11:00 a.m. that morning, plant personnel
"un-bypassed" the inoperable channel while troubleshooting.
A note in the OWP erroneously stated that returning the trip switch (BS-1) to the NORMAL position in step 6 did not affect the bypassed condition of the channel.
Consequently, plant personnel left the trip switch in the NORHAL position after troubleshooting.
The next morning, while preparing to do a calibration for operability, maintenance technicians discovered that inoperable level channel for LT-0991 had been
"un-bypassed" for nearly 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while normal plant operations continued, contrary to the TS action statement.
Upon discovery, the channel was satisfactorily calibrated and restored to operability.
The inspector discussed this incident with procedure writers, maintenance technicians, and engineers.
The procedure note had been included during a November 1995 revision and was based on erroneous
I
2.7 assumptions that a lifted lead in the circuit would ensure that the channel was bypassed, regardless of the trip switch position.
A post-event review of the associated logic diagram with engineering personnel confirmed that the lifted lead had no impact on the bypassed state if the trip switch was returned to NORMAL.
As an immediate fix, the OWP was revised removing the note and subsequent step 6.
A CR was written and a licensee root cause investigation was ongoing at the end of the inspection period.
The inspector will track the licensee's actions regarding this incident as Unresolved Item 400/96-01-02:
Inoperable RWST Level Channel Improperly Returned to Service.
.
Review of Overtime Usage The inspector reviewed a random selection of time sheets for Operations personnel to determine'hether overtime usage complied with requirements in TS 6.2.2.f.
This review included time sheets for auxiliary operators, licensed reactor and senior reactor operators, shift supervisors, and shift technical advisors.
Time sheets for nearly 30 people were reviewed from Hay 1995 through November 1995 to include months affected by recent refueling and forced outages.
The TS stated that adequate shift coverage shall be maintained without routine heavy use of overtime.
For unforeseen problems or during extended periods of shutdown, the TS imposed the following limits (all excluding shift turnover)
on individuals performing safety-related functions, including operators:
No more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight; No more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period; and A break of at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> should be allowed between work periods.
Operating shifts at Harris are 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (6:00 to 6:00) in length.
Shift turnovers have combined times of 30 minutes to an hour daily, depending on plant status.
Hence, an operator can generally charge 12.5 to 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> on a routine day without exceeding any of the above limits.
In non-outage months, a shift usually works 3 or 4 days (nights)
a week, or more depending on how the shift rotates.
During the last refueling outage (September October 1995), the plant adopted a six-days-on/two-days-off policy, with a one-hour shift turnover built into the schedule.
For the time sheets reviewed, the inspector found that the majority of operators charged time within the above limits.
In very few cases, charged time exceeded some of the above limits.
In those situations, as allowed by the TS, deviations were usually pre-approved by the Plant General Manager or his designee.
This was done in accordance with forms provided in administrative procedure AP-012, Revision 1, Control of Overtime Hours.
The most commonly exceeded limit was the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a
48-hour period, followed by the 72-hour/7-day limit.
In such approved
2.8
cases, operators usually charged more time than usual to attend a
special meeting or cover for a no-show relief operator.
The inspector identified four questionable cases where TS overtime limits appeared to be exceeded without prior plant management approval.
However, further inquiries determined these cases to involve longer than usual shift turnovers, or in one case, attendance at a meeting where no work was performed prior to going off shift for two days.
Shift turnover hours were explicitly exempted by the TS, and the special meeting case was determined by the inspector not to violate the intent of the TS requirement.
The inspector noticed that in months leading up to and during the last refueling outage, operators worked large amounts of overtime.
In almost all cases reviewed, operators worked 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> in 7 day periods.
These included six 12-hour shifts plus one-hour shift turnovers (30 minutes on'ach end).
Hence, both the 72-hour/7-day and the 24-hour/2-day TS limits were heavily challenged - but not exceeded
- during this period.
The operations shift schedule is designed with a small amount of overtime (approximately 6 or 7 percent) built into it, even during non-outage months.
However, a review of year-end statistics showed that, on average per operator, between 20 and 25 percent of total time worked was overtime.
Some operators approached 30 percent overtime.
Discussions with Operations management personnel indicated that these numbers exceeded the plant's goals for 1995.
A review of a root cause investigation conducted by the licensee for recent human errors indicated that some operators perceived overtime usage to be excessive.
Plant management added that overtime usage in 1995 had increased over the previous year.
At the end of the inspection period, plant management was evaluating recent overtime statistics and addressing ways to possibly reduce it.
The inspector concluded that any excessive overtime usage occurred primarily to support refueling outage activities (as allowed by TS with prior management approval),
and that overtime hours were maintained within TS limits.
The inspector identified no TS violations or deviations in operator overtime usage.
Effectiveness of Licensee Control in Identifying, Resolving, and Preventing Problems CRs were reviewed to verify that TS were complied with, corrective actions and generic items were identified, and items were reported as required by
CFR 50.73.
Licensee personnel generated CRs, for the RABEES and RWST level channel incidents discussed in paragraphs 2.4, 2.5, and 2.6 of this report; and promptly initiated root cause investigations, recommended interim corrective actions, and satisfied reporting requirements when due.
As indicated in paragraph 2.4 above, the inspector was concerned with previous corrective actions for RABEES door incidents (all documented in CRs).
Other CRs described events which were reported as LERs and described in paragraph 2.9 of this repor The inspector reviewed a
CR generated when operators discovered that an AFW system surveillance test procedure had not been updated to include newly revised inservice testing acceptance criteria for the AFW flow control valves.
Procedure OST-1211, Revision 4, Auxiliary Feedwater Pump 1A-SA Operability Test, quarterly Interval, was performed on January 24.
The procedure was stopped during performance after a
typographical error was discovered, following which discussions ensued concerning the omitted IST data.
The test acceptance criteria (a valve open stroke time of 2 seconds),
had been developed by ISI personnel in July, 1995.
A procedure revision was planned, but writers delayed implementation since the test was not scheduled to be performed until February 2.
When test performance was moved up on the schedule to January, the procedure was issued and performed without the new acceptance criteria.
The licensee's interim corrective actions for this mistake included revising the procedure and counseling procedure writers'ho had not implemented the licensee's program for placing procedures on administrative hold pending such changes.
The inspector verified that the missed criteria did not cause the AFW system to be inoperable.
The procedure was subsequently re-performed satisfactorily.
The inspector'onsidered this example, in aggregation with other procedural deficiencies noted in recent inspection reports (IRs 400/95-15, 95-17, 95-19, and paragraph 2.6 of this report), to represent a
potential negative trend in the quality of operations procedures.
This concern was discussed with plant management who indicated that they were addressing the noted deficiencies.
Licensee management commented that some of the recent deficiencies had been identified because of increased efforts to identify procedure problems, whether grammatical or technical in content.
The inspector acknowledged the comment and explained that examples cited in the inspection reports were of a more technical nature, some of which were self-disclosing and resulted in reportable events.
2.9 2.9.1 2.9.2 Review of LERs - Plant Operations (Closed)
LER 400/96-001-00:
Reactor Auxiliary Building Door Found Blocked Open Resulting in Entry into Technical Specification 3.0.3.
The LER, dated February 9,
1996, accurately described the scenario involving the inoperable RABEES system.
Violation 400/96-01-01 was issued (described in paragraph 2.4 of this inspection report) for inadequate corrective actions for controlling RABEES doors.
The licensee's corrective actions for the violation, including those committed to in the LER, will be tracked under the violation.
This LER is closed.
(Open)
LER 400/95-012-00:
Containment Pre-Entry Purge Valve 1CP-1 Drifted Open During Node 1 Power Operation.
This LER was previously discussed in NRC IR 400/95-18.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement
Policy, and is identified as NCV 400/96-01-03:
Failure to Properly Secure Containment Isolation Valve CP-1.
As-stated in the previous inspection report, the LER will remain open pending the inspector's review of the licensee's corrective actions.
2.10 2.11 3.0 3.1 Closure Items - Plant Operations (Closed) Violation 400/95-18-01:
Failure to Report TS Violation Involving Improper Verification of Offsite Power Availability.
By letter dated January 18, 1996, the licensee admitted to the violation as cited, attributed the violation to personnel error involving inadequate review of TS requirements, and committed to counseling the involved individual, which was done on December 7,
1995.
Full compliance was met when the violation was reported in LER 95-13-01 on January 4,
1996.
This item is closed.
Conclusion - Plant Operations Overall in the Plant Operations area, one violation was identified by the inspector for inadequate corrective actions in controlling RAB emergency ventilation boundary doors.
A cold weather spell caused two RWST level channels to become inoperable, requiring plant entry into TS 3.0.3.
An unresolved item was opened concerning a possible TS violation involving an inoperable RWST level instrument channel being placed in service.
Inattention to detail was noted by the inspector in assigning caution tags for control board switches.
Operators'vertime usage was found to be in compliance with the TS.
Recent operations procedure deficiencies (including those identified in Operations Surveillance Tests)
have indicated a potential negative trend in that area.
Plant management has developed a program designed to more effectively use management in the field.
Overall, plant operations were conducted satisfactorily.
MAINTENANCE - (62703, 61726, 92700, 92902)
Maintenance Observations The inspectors observed portions of the following activities:
AGVC-001 MPT-I0005, Matheson Flow Transducer Transmitter Calibration (Postaccident Sample System)
ACKET-001 PIC-I914, Comparator 8 Rate Orawer N37/N46 (Rate Section)
Calibration.
The inspectors found the work performed 'under these activities.-to be professional and thorough.
All work observed was performed with the work package present and in active us.2 Surveillance Observations 3.2.1 3.2.2 The inspectors observed performance and reviewed data for the following surveillance tests.
OST-1011, Auxiliary Feedwater Pump 1A-SA Operability Test Monthly Interval, Modes 1-4.
This procedure partially satisfied TS 4.7.1.2.1.a by verifying the "A" AFW pump developed a differential pressure that (with temperature compensated to 70 degrees F) was greater than or equal to 1514 psid at a
recirculation flow greater than or equal to 50 gpm.
The procedure also verified that each valve that was not locked, sealed, or otherwise secured in position was in its correct position; and that the CST isolation valves in the pump suction line were locked open.
The inspector observed good procedure adherence.
The inspector reviewed the differential pressure calculations which were satisfactory.
This test procedure required closing the AFW pump discharge isolation valve which temporarily made the "A" train inoperable.
The inspector thus verified that this job was properly scheduled in accordance with the risk matrix used in implementing the licensee's on-line maintenance/surveillance program.
Calibrated test equipment was used.
All tested parameters s'atisfied TS requirements.
Personnel performance during this evolution was good.
EST-910, Revision 1, Hot Channel Factor Tests (Powertrax Version)
FHP-201, Revision 1, Incore Flux Mapping Using Powertrax FHP-200, Revision 1, Full Core Flux Map Review Checklist (Powertrax Version)
The above procedures were all associated with core flux mapping activities conducted on February 6,
1996.
Procedure EST-910 satisfied requirements in TS 4.2.2.2.
Procedure FMP-201 satisfied the surveillance requirement in TS 4.3.3.2c.
Procedure FHP-200 provided a
means for reviewing and evaluating full core flux map for any suspect data or potential core anomalies prior to using the data to satisfy TS requirements.
The inspector verified that the required minimum number of detector thimbles were used to perform the flux map.
The inspector observed that engineers followed the above procedures in acquiring and analyzing core map data.
At one point, while performing step 6.2.5 of procedure FMP-200 which compared duplicate flux traces, the engineer referred to the wrong data sheet.
This error was corrected on the spot and the engineer subsequently referred to the correct data.
In reviewing the engineers'alculations, the inspector found no errors.
Hot channel factors were within acceptable limits for the three different types of fuel designs currently loaded in the Harris reactor vessel.
quadrant power tilt ratios were all within the TS limit as well.
Overall performance during these procedures were goo.2.3 3.2.4 3.3 3.3.1 EST-708, Revision 8, Monthly RCS Flow Determination This procedure satisfied the monthly requirement in TS 4.2.3.3.b.
The inspector verified that the proper plant computer points were used in acquiring real-time RCS loop flow readings.
Data was correctly converted to gpm (from percent RCS flow) and compared to TS limits.
Actual RCS flow was determined to be within the Permissible Operation Region defined by the TS.
The inspector concluded that procedure performance was good.
EPT-033, Revision 9, Emergency Safeguards Sequencer System Test This procedure was a reliability test developed to verify that the various sequencer programs (Loss of Offsite Power, Loss of Coolant Accident, and the combination of both) operated per design.
This test was performed on January 31 for the "B" train sequencer.
While the test was not credited for any TS surveillance requirement, it did perform testing as described in FSAR Section 7.3. 1.
The inspector compared this FSAR section to the procedure and identified no discrepancies.
During the portions of the test observed, relays and annunciators in the sequencer panel functioned as required.
Persons performing the procedure exhibited good compliance and all steps were initialed as required.
Review of LERS Maintenance (Closed)
LER 400/95-016-00:
Unexpected Opening of the "A" Reactor Trip Breaker During Testing, Constitutes an Unplanned ESF)RPS Actuation.
This LER, dated January 29, 1996, appropriately described the circumstances surrounding an incident on December 28, 1995 in which the
"A" reactor trip breaker was cycled three times during SSPS logic testing.
The breaker initially opened unexpectedly when technicians took the SSPS Logic "A" Test Switch to the OFF position after completing a test for pressurizer high pressure trip circuitry.
The switch was rotated clockwise through contacts associated with the "power above
percent (P-10) permissive".
This, in conjunction with the plant being in Node 3 (with the four turbine throttle valves shut and low turbine auto-stop oil pressure satisfying turbine tripped logic), allowed a trip signal to be sent to the
"A" RTB, which functioned as designed.
Since the breaker opening was unexpected, technicians in an unapproved trouble-shooting attempt, re-performed related sections of the test procedure.
They assumed their actions.to be consistent with acceptable troubleshooting practices as described in the test procedure.
However, plant administrative guidelines on troubleshooting required an approved plan be developed prior to taking such actions, seemingly contradicting information in the technical surveillance procedure.
The technicians caused the breaker to open twice more before the shift supervisor was notified.
The safety consequences of the event were minor.
No other equipment was actuated during the event, and the plant was already shutdown for a preplanned forced outag The licensee determined the cause of the initial breaker opening to be an inadequate procedure.
During the test, a step in the procedure (HST-I0001, Revision 6, Train A Solid State Protection System Actuation Logic E Haster Relay Test) required that the "input error inhibit" switch be placed in NORHAL versus INHIBIT to allow verification of P-4 (Reactor Trip) permissive voltage.
This instruction had been in the procedure since 1985 when the circuit was modified to allow for the voltage verification.
While the quarterly procedure had been performed numerous times in the 10 years since, the procedure was either performed with the plant in Node 1 (hence turbine trip logic not satisfied),
or the SSPS
"A" Logic Test Switch was always rotated in the counterclockwise position to OFF, thereby avoiding test contacts associated with the P-10 permissive.
The direction of switch rotation, whether counterclockwise or not, was not proceduralized but had recently been specified by engineers interested in reducing the possibility of residue build-up on
'he infrequently "wiped" switch contacts.
While this explained the first incident, the second and third breaker openings were attributed to personnel error.
The licensee corrected the procedural deficiency (along with similar deficiencies in other quarterly and 18-month test procedures)
prior to issuing the LER.
Steps were corrected requiring that the "input error inhibit" switch be placed in INHIBIT anytime the logic test switches are removed from the OFF position.
Personnel were counseled on the importance of proper communication of unexpected test occurrences and the need for troubleshooting in accordance with approved plant guidelines.
The inspector considered the licensee's root cause investigation to be thorough.
Licensee management's actions to address the improper troubleshooting of the test circuit were considered adequate.
The inspector considered the personnel errors in that regard to be isolated events.
Surveillance procedural deficiencies have been an acknowledged problem that the licensee has been addressing through the Technical Specification Surveillance Review program scheduled for completion later in 1996.
This program was prompted by previous problems with emergency battery testing, thermal overload bypass testing, auxiliary contact testing, and testing of the recently modified AFW flow control valve circuitry.
This LER is closed.
3.3.2 (Open)
LER 400/95-014-00:
Residual Heat Removal System Components Were Removed From Service as Directed During Testing, While Required for Operability, Resulting in a Technical Specification Violation.
During refueling outage 5 in April 1994, the plant was in mode 6 and RHR system check valve testing was in progress.
As directed by surveillance procedure steps, operators were allowed to remove control power fuses associated with the.RHR pump motor breakers (one train at a time) to support testing.
With the plant in Mode 6 and refueling cavity water level less than 23 feet, TS 3.9.8.2 required both trains of RHR to be
With the control power fuses removed (necessitating operator action outside the main control room to restore the pumps),
the licensee determined that each RHR train was separately inoperable for approximately 22 minutes apiece (total 44 minutes).
This was contrary to the TS requirement which contained an action statement to return the inoperable train to operable as soon as possible.
The licensee's inoperability determination was made on December 14, 1995 after its investigation into a similar near-miss situation identified by plant operators during refueling outage 6 in September 1995.
The LER was appropriately issued on January 12, 1996.
The licensee attributed the event to a surveillance procedure inadequacy which allowed the control power fuses to be removed without considering the impact on RHR operability while in Mode 6.
The licensee committed to revising the procedure (OST-1508, ISI Operability Test for 1CS-167, 1CS-294, 1CS-775, 1CS-776)
by February 15, 1996.
The safety significance of this event was reduced by the fact that one train of RHR was always available and operators could have quickly restored the opposite train by installing the control power fuses if needed.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy, and is identified as NCV 400/96-01-04:
RHR Inoperability During Mode 6 Caused By Procedure Error.
The LER will remain open pending inspector verification of the licensee's corrective actions.
3.4 Self Assessment Maintenance 3.5 The licensee's NAS performed a two week assessment of maintenance on January 8 through 19, 1996.
The report for this assessment (Report No.
H-MA-96-01) was issued on February 6,
1996.
The inspectors reviewed the final report and discussed the conduct of the assessment with NAS.
The issues identified by the NAS assessment included problems with procedures and the use and adherence to procedures; poor identification and tracking of overdue and unsatisfactorily performed PM tasks; inadequate use of self assessment by maintenance; and inconsistent use of good work practices by maintenance craft personnel.
This assessment is in close agreement with an apparent increase in identifieQ problems with procedure and procedure compliance noted by the inspectors during trending of maintenance-related NRC inspection findings and licensee identified findings such as LERs, CRs, etc.
Comprehensive resolution of the findings of the NAS assessment should provide significant improvement in the conduct of maintenance at this facility.
Conclusion Maintenance Overall, maintenance and surveillance activities observed by the inspectors were performed well.
Surveillance procedure performance was satisfactory with proper use of calibrated test equipment, necessary communications established, notification/authorization of control room
personnel, and knowledgeable personnel having performed the tasks.
The inspectors observed no violations or deviations in this area.
One slave relay test procedure (performed in December 1995 but documented in an LER during this period) resulted in the unexpected opening of a reactor trip breaker while the plant was already shutdown.
Related to that event, test procedure deficiencies and personnel errors were identified and corrected by the licensee.
Another licensee-identified violation was noted involving a surveillance procedure.
This NCV involved a
procedural deficiency that was more than a year old, but identified during recent licensee activities.
The licensee is currently implementing a Technical Specification Surveillance Review project (which was developed prior to but in accordance with NRC Generic Letter 96-01, Testing of Safety-Related Logic Circuits) to further identify and correct other potential logic testing deficiencies.
The licensee expects to complete this program later in 1996.
A NAS maintenance assessment was thorough in identifying recent maintenance performance trends.
4.0 4.2 ENGINEERING (37550, 92903)
The inspectors reviewed the design change program, the engineering backlog, engineering involvement in inspection of safety-related dams, engineering response to emergent issues, and audits of the design change program.
Design Change Control Processes The inspectors reviewed the current revisions of the procedures listed below which control design changes and verified that design control measures were consistent with 10 CFR 50, Appendix 8, Criterion III.
The following procedures were reviewed:
ENP-005, ESR Hodification Implementation; ENP-010, Preparation and Control of Design Basis Documents; ENP-011, Preparation and Control of Design Analyses and Calculations; ENP-012, Preparation and Control of Design Drawings/Sketches; ENP-013, Preparation and Control of Specifications; ENP-014, Review and Control of Externally Generated Design Documents; ENP-016, Design Verification And Radwaste g-Review; ENP-017, Plant guality Listings; and PLP-650, Engineering Service Request.
The inspectors concluded that the following attributes were adequately addressed:
design processes, design inputs, interface controls, design verification, document control, post-modification testing, control of field changes, and
CFR 50.59 safety evaluations.
The inspectors concluded that adequate controls were in place to ensure effective implementation of design changes.
Review of Engineering Backlog The inspectors reviewed the backlog of items in the HESS.
These items included ESRs, temporary modifications, drawing changes, and open
4.3 engineering responses.
The majority of the items in the backlog were opened less than one year ago.
The items opened prior to 1995 involved lower priority issues.
The overall number of items in the backlog was within acceptable limits.
None of the open items affects equipment or system operability.
The inspectors concluded that the licensee was effectively managing their engineering workload and completing engineering work activities in a timely manner.
Review of Design Change Packages The inspector reviewed a sample of ESRs which covered minor and major design changes to determine if they were being implemented in accordance with the licensee's design change procedures.
The following design change packages were reviewed:
ESR 9400022 ESR 9400085 ESR 9400110 ESR 9400247 ESR 9400345 ESR 9400364 ESR 9400387 ESR 9500125
- Temporary closure plate for equipment hatch
-
PCR 7406 Hissing load pin on support I-CS-H-4261
- Removal of internals for valve 1RC-993
- Hissing fire damper AH-13
- Containment walkdown pipe hanger as-built issues
-
RAB and DGB pipe hanger as-built walkdown issues
- Hain steam tunnel support evaluation Structural steel removal to support PCSR ESRs 9400022 and 9500125 were classified as major design changes, with the remainder classified as minor design changes.
The inspectors verified that the
CFR 50.59 safety evaluations were adequate,
'the modifications were reviewed and approved in accordance with the licensee's procedural requirements, applicable design bases were considered, and appropriate post-modification testing requirements were specified.
The inspectors also verified that work instructions, including drawings and specifications, were adequate to implement the modifications.
The inspectors also performed an additional review of PCR 6502, Startup Feed Pump (Auto-open Signals to AFW Flow Control Valves).
The inspectors noted that the licensee's engineering evaluation discussed the potential detrimental effect of low flows from the AFW pumps on the AFW check valves.
The PCR contained a recommendation that additional inspections be performed on these valves so that the impact of reduced AFW flow can be monitored.
The inspectors discussed the program to monitor these valves with ISI engineering personnel.
These discussions disclosed that the valves have been included in an increased frequency inspection program.
The program specified that the valves in one train of the AFW system be inspected each refueling outage.
The inspectors reviewed the results of the valve disassembly inspections performed on the "A" train AFW valves during the September 1995, refueling outage.
No deficiencies were identified.
The inspectors concluded that the valve inspections were being performed in accordance with the recommendations made by design engineers.
Other licensee-identified deficiencies associated with this modification are discussed in paragraph 4.6 of this repor Review of Calculations 4.5 The inspector reviewed calculation numbers HNP-C/STRU-1019, Removal of Containment Equipment Hatch, Rev.
3 and HNP-C/STRU-1024, Hissile Block Drop/Storage on WPB Roof, Rev. 1.
Both calculations were generated to support ESR 9500125.
The calculations were reviewed for completeness, accuracy, adherence to design criteria and the FSAR, adherence to procedural requirements, and acceptability of calculation methods in accordance with industry standards"(codes)
and good engineering practices.
Calculation HNP-C/STRU-1019 was generated to qualify methods for removal of the containment equipment hatch.
The qualification included:
(1)
evaluation of the structural stability for seismic loadings after two hatch braces were removed to facilitate transport of the reactor coolant pump motors; (2) installation of a 24-ton monorail hoist on the existing monorail beam to remove and hold the equipment hatch door; (3)
evaluation of the roof slab to support crane loads during reactor cooling pump lifting; and (4) evaluation of a 24-ton crane to lift the missile shield concrete blocks and store them on the roof slab.
The inspector verified the damping values, seismic coefficients, beam and slab allowables, crane information and concrete compressive strength.
The inspector concluded that proposed methods to remove the equipment hatch were acceptable.
Calculation HNP-C/STRU-1024 evaluated the temporary storage of concrete missile shield blocks on the roof of the waste processing building.
The inspector verified design loads and design allowable values used in the calculation and found them valid.
The inspector concluded that temporary storage of the shield blocks was acceptable.
In general, the inspectors considered the design calculations to be thorough, based on clarity, consistency, and accuracy.
The calculations served their intended function to assure the plant implemented appropriate modifications.
Inspections of Safety-Related, Water Control Structures The inspectors performed a visual inspection of the West Auxiliary dam and the separating dike.
These structures provide emergency cooling water for the plant.
Features examined included the upstream and downstream embankment slopes, the crest, slope protection, concrete structures, and the downstream toe of the dam.
Some vegetation growth was noted on the embankments; however, the licensee was controlling the vegetation using herbicides.
Following the last NRC/FERC audit of this area (documented in NRC IR 400/95-01),
the licensee retained a
contractor who removed all trees growing within 20 feet of the downstream toe of the dam.
The inspectors also reviewed Law Engineering Report dated December 1995, titled "1995 Water Control Structures Inspection - Final Report".
This report summarized the results of the five-year periodic inspection
4.6 completed in 1995, as specified in FSAR Section 1.8.
The licensee indicated that work requests would be initiated to address the minor maintenance items identified in the Law Report.
The inspectors also reviewed piezometer data, survey data, and slope deflection data recorded in 1995.
The data showed no change since the last NRC review conducted in January 1995.
The licensee corrected settlement around a
monument on the main dam in accordance with WR/JO 95-ABJEl.
The overall condition of the structures was good.
guality Assurance Assessment and Oversight The inspectors reviewed assessments performed by NAS of engineering activities.
Findings from these assessments were categorized as strengths, issues, or weaknesses.
The inspectors also reviewed self assessments conducted in 1995 of engineering activities within HESS.
The self assessments were conducted in accordance with procedure PLP-003, Self Assessment.
The self assessments and NAS assessments were part of the overall CP&L quality assurance program at Harris.
The NAS assessments reviewed by the inspectors were assessment numbers H-MOD-94-01 and H-NOD-95-01.
One issue and two weaknesses were identified in assessment H-NOD-94-01.
The issue concerned inattention to detail resulting in incorrect and inadequate design package documentation.
The weaknesses concerned failure to adequately document NED engineer training and failure of the design review process to question a design input based on vendor telecon.
One issue and one weakness was identified in assessment H-MOD-95-01.
The issue concerned HESS personnel inadequately tracking modification exceptions.
The weakness involved resolution of review comments for approved ESRs.
The inspectors revi ewed the licensee's corrective actions for the NAS findings.
The inspectors learned that the weakness regarding vendor telecon input involved PCR-6502, Start-up Feed Pump.
This modification provided automatic opening signals to three AFW flow control valv'es so that they could be throttled during plant start-ups.
Subsequent to assessment H-NOD-94-01 and implementation of this modification, numerous post-modification testing deficiencies were identified regarding PCR-6502.
Some of these have resulted in LERs (see paragraph 3.3.3 of this report).
Because of the identified deficiencies, a self assessment was conducted by the NED Chief Engineer's Office to determine if all procedures affected by the modification process have been identified, reviewed, and revised.
Numerous findings were identified during this self assessment.
The licensee was implementing corrective actions to address these issues.
The inspectors concluded that the audits of engineering activities were effective in identifying engineering performance deficiencies and were useful in providing'oversight to management.
Corrective actions. in response to the audit findings were gener ally acceptable.
However, additional review will be performed regarding the licensee's corrective actions for the NED assessment of PCR 650.7 Engineering Response to Emergent Issues The inspectors discussed with engineering supervisors the methods used within the HESS for handling daily emergent issues.
These discussions disclosed that the normal point-of-contact in engineering for operations or maintenance personnel when an operational problem occurs is the HESS Rapid Response Team who then obtains any additional engineering assistance necessary to resolve the issue.
The Rapid Response Team is located in the maintenance building.
The response time to various issues is dependent on the type and seriousness of the problem.
However, most issues are handled by a telephone request for assistance.
Response to issues is not delayed pending receipt of formal written requests for assistance.
When problems occur outside of normal business hours, engineering assistance is requested through the "duty" engineer who is on call 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day.
Operations and maintenance personnel stated that, during off duty hours, they could also directly contact any responsible engineering supervisor at his/her residence or via pagers.
Operations and maintenance personnel indicated that support from engineering in responding to emergent issues has been excellent.
The inspectors concluded the licensee's system for responding to engineering issues is effective.
No examples were identified where resolution of problems was delayed by lack of response from engineering personnel.
4.8 Review of LERS - Engineering (Open)
LER 400/95-015-00:
Failure to Identify Engineering Safety Features Response Time Testing Requirements During a Modification to the Flow Control Valve Circuitry for Motor Driven Auxiliary Feed Water Pumps.
This LER, dated January 11, 1996, described the licensee's failure to identify response time testing requirements for the AFW flow control valves (1AF-49, 1AF-50, and lAF-51).
These valves were modified in 1994 to automatically open during any actuation signal for the AFW pumps (including SI, loss of both main feed pumps, etc.).
Licensee personnel discovered, through a
NAS response time testing assessment in December 1995, that these valves were not appropriately response time tested as required by TS 4.3.2.2, Engineered Safety Features Actuation System Instrumentation.
While the valves have been tested for IST data since the modification was installed, the method of IST testing did not incorporate the system alignment required for response time testing.
Likewise, the valves were opened during IST testing by sending a
"pump off" or "fail-safe" signal to their controllers.
Response time testing requirements were such that the test must be done with the AFW pumps running.
Therefore, licensee personnel could not take credit for the IST data to satisfy TS 4.3.2.2.
The licensee attributed the testing deficiency to personnel error during development of the auto-open modification.
Neither the engineers developing the modification nor personnel reviewing it recognized that
response time testing should be considered.
To correct this problem, the licensee has committed to training select engineering personnel on response time and overlap testing.
Likewise, modification procedures will be revised requiring a review of components which may affect safety actuation signal response time.
To correct the specific problem with the AFW flow control valves, applicable test procedures were revised and the valves were tested satisfactorily on December 15 and 25, 1995.
A review of previous IST data provided assurance that the valves (which typically open in 2 seconds)
would have satisfied the AFW system response time requirement of 60 seconds.
In the interim, prior to the December tests, administrative controls were in place to ma'intain the valves full open their safe accident position.
~ Problems related to testing this auto-open feature have been discussed in two other LERs (LERs95-009 and 95-011)
and another pending LER.
The causes for these events have centered around either the 1994 modification discussed in paragraph 4.6 of this report, or the subsequent development of test procedures associated with the auto-open feature.
The inspector considered the cause of this latest incident to be unique in its relationship to response time testing and concluded that the violation, which actually occurred in 1994 during development of the modification, could not reasonably have been prevented by the licensee's corrective actions for previous violations.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy, and is identified as NCV 400/96-01-05:
Failure to Incorporate Response Time Testing Requirements for AFW Flow Control Valves.
The LER will remain open pending licensee implementation and inspector review of corrective actions.
4.9 Closure Items - Engineering (Closed)
IFI 400/94-03-01:
Corrective Actions for ACFR 93-560 Concerning Temporary Modification Renewals not Beihg Performed.
An adverse condition and feedback report, ACFR 93-560, was identified when a temporary modification, TH PCR 6927, was not renewed after 90 days in accordance with modification procedure MOD-206, Temporary Modificatsons.
The licensee's corrective actions were not yet completed during the inspection documented in NRC IR 400/94-03.
During that same inspection, the inspectors identified another expired temporary modification which had not been renewed after 90 days.
The licensee determined that these errors were due to the fact that the TH had been partially closed, a status that was not addressed in procedure MOD-206.
The licensee's corrective actions included re-opening TH PCR 6927, and revising it to reflect actual field conditions.
The licensee also revised procedure MOD-206 to emphasize that partial closure of THs was not permitted.
The inspector reviewed Revision 4 of procedure HOD-206, dated March 25, 1994, and verified that requirements for partial closure of THs was clarified.
The inspector also reviewed procedure ENP-005 and PLP-650 and verified requirements for partial closeout of THs were
clarified.
The licensee's program now requires that the scope of the temporary modification be revised after partial closure so that actual field conditions are reflected.
4.10 5.0 5.1 Conclusion - Engineering The licensee was effectively managing engineering backlog.
Engineering self assessments were effective, providing useful oversight to plant management.
Engineering response to emergent issues was good.
Design packages and calculations were thorough.
One design package (PCR 6502)
associated with AFW flow control valves resulted in numerous testing deficiencies identified by the licensee.
The licensee is currently implementing corrective actions for those items.
The West Auxiliary Dam and the separating dike were in good condition.
One licensee-identified Non-Cited Violation was noted for failure to perform response time testing for AFW flow control valves.
PLANT SUPPORT (83750, 84750, 86750, 82701, 71710, 71750)
Environmental and Radiation Control Organization and Staffing TS 6.2 described the licensee's organization.
Changes in E&RC Organization and its personnel were reviewed to assess their impact on the effectiveness of plant programs to control radioactive material and radiation exposures.
The inspectors reviewed and discussed with licensee representatives changes made to the E&RC organization since the last inspections of these areas.
The E&RC Organization was divided into the Radiation Control Branch and the Environmental and Chemistry Branch.
E&RC Support (formerly an independent branch in the organization but now within the Radiation Control Branch)
had been expanded to include radwaste and spent fuel shipping, and technical support.
This group included a team of analysts, technicians, and mechanics whose principal duties dealt with the receipt of spent fuel from other CP&L nuclear plants, annual inspections of the spent fuel casks, maintenance in the Fuel Handling Building, and the future material upgrades (painting, addition of spent fuel racks, and the cleanup/control of the crud which has been allowed to settle on.the floor of the Spent Fuel Pool).
Each of the two branch superintendents reported to the E&RC Manager.
The inspectors noted that the organization and staffing had remained relatively stable and that the E&RC organization continued to be staffed sufficiently to support ongoing radiological health programs and necessary RC shift coverage during normal plant operations.
The inspector reviewed the continued policy of reassigning HP Technician resources from Harris for temporary duty with the other CP&L nuclear sites during their outages.
The inspector conducted this review to determine whether adequate technician staffing remained at Harris during normal Harris plant -operations.
The inspector noted that since the previous inspection, the position of Nanager, E&RC, was temporarily vacant with the incumbent absent to attend reactor operator training for approximately six months.
The position of Superintendent-E&C, Environmental and Chemistry programs, was also being filled through an
acting assignment in the absence of the incumbent who was also attending reactor operator training.
The E&RC organization was temporarily restructured with managers in the radiation protection area and in the environmental and chemistry area reporting directly to the Plant General Manager.
The educational and experience backgrounds of the personnel assigned both permanently and in an acting capacity to these positions were reviewed against FSAR commitments, ANSI 3. 1
& Reg.
Guide 1.8 criteria, as well as plant procedures, with no concerns noted.
The inspector noted that the temporary personnel assignments should not adversely affect the RC program specifically in that the Superintendent-
.
E&RC for Radiation Protection programs, who also fulfills FSAR qualifications as the Radiation Protection Manager, remained constant.
The inspectors concluded that the licensee's E&RC Organization satisfied TS requirements and noted that the recent personnel changes within the E&RC function did not appear to adversely affect the organization's ability to function effectively to protect the health and safety of members of the public as well as plant workers.
The E&RC organization and staffing levels continued to be appropriate to support ongoing E&RC activities.
No violations or deviations were identified.
5.2 5.2.1 Primary Water Chemistry During this inspection, the plant was in its seventh fuel cycle and was operating at 100 percent power.
The sixth refueling outage was completed in October 1995.
The inspector reviewed the plant chemistry
,
controls and operational controls affecting primary water chemistry since the last inspection in this area.
TS-Required Parameters TS 3.4.7 specified that the concentrations of 00, chloride, and fluoride in the RCS be maintained below 0. 10 ppm, 0. 15 ppm, and 0. 15 ppm, respectively.
TS 3.4.8 specified that the specific activity of the primary coolant be limited to less than or equal to 1.0 I Ci/g DEI.
Pursuant to these requirements, the inspector reviewed graphical daily summaries and monthly reports which correlated reactor power output to chloride, fluoride, and dissolved oxygen concentrations; and specific activity of the reactor coolant for the period of November 1,
1995 through January 17, 1996.
The inspector determined that the parameters were maintained well below TS limits.
Typical values for 00, chloride, and fluoride were less than two ppb, less than five ppb, and five ppb for each of the respective parameters.
A typical DEI value at steady-state conditions was 6.0E-3 pCi/g.
The licensee had not identified any defective fuel pins during the current fuel cycle.
The inspector concluded that the primary water chemistry was well-maintained and satisfied TS requirement.2.2 Early Boration
~
~
The licensee has used early boration (acid-reducing chemistry)
combined with hydrogen peroxide injection (acid-oxidizing chemistry) during the last four unit shutdowns/cooldowns at refueling (Refueling Outages
through 6) to reduce the source term.
The inspector reviewed the licensee draft report of the most recent early boration results (RFO 6).
The 'process removed 513.6 curies of activated corrosion products via the CVCS mixed bed demineralizer.
This.
total included 422.6 curies of Co-58, 49.7 curies of Cr-51, 23. 1 curies of Hn-54, and 17.9 curies of Co-60.
In addition, 1740 grams of nickel (which can be activated during power operation to produce Co-58)
and 216 grams of iron were removed.
Degassing of the RCS collected a total of 65 curies of fission gases.
The average dose in the SG channel heads was reduced approximately 10. 1 percent, due to the removal of the activated corrosion products.
The following table summarizes the results of the early boration efforts at Harris.
TABLE Parameter RF03 RF04 RF05 RF06 Total Curies Removed Co-58 (curies)
Co-60 (curies)
Mn-54 (curies)
Cr-51 (curies)
Cs-134/137 (cur ies)
Nickel (grams)
Iron (grams)
Chromium (grams)
591.4 499.8 26.8 47.5 17.4 1285.0 70.0 0.0 716.2 560.6 47.7.
33.1 74.9 2212.7 312.3 8.4 654.8 492.1 47.1 30.0 88.7 87.5 1539.2 13,7. 8 2.3 513.6 422.6 17.9 23.1 49.7 0.0 1740.0 216.2 3.8
- Note:
Cesium activity was not tracked during the RF03 and RF04 shutdowns.
Although fewer total curies were removed during the last refueling outage, the average dose in the SG channel heads was reduced approximately 10. 1 percent, the first reduction in the plant's history.
The licensee attributed this to several factors.
These included principally tight pH control during the fuel cycle and a mid-cycle outage (October November 1994) during which approximately 1400 grams of nickel were removed from the RCS.
The nickel concentration was reduced to less than 100 ppb to begin the operational lithium control program, thereby reducing the RCS Co-58 inventory for RF06.
Other potential factors were good fuel performance (no leakers)
during the fuel cycle and less time spent in the acid reducing phase, which may have resulted in lower decomposition of nickel ferrite during the cooldow.3 5.3.1 Based on the results of these reports, the inspector concluded that the licensee, was proactive in trying to reduce dose rates by removing significant quantities of radioactivity via its early boration program.
Secondary Water Chemistry TS 6.8.4.c required the licensee to establish, implement, maintain, and audit a Secondary Water Chemistry Program to inhibit SG tube degradation.
General Program The inspector discussed the impact of the licensee's program and its impact on the condition of the SGs.
The licensee used an ETA regimen since January 1994, when it replaced ammonia, at concentrations ranging
'rom 1.0 ppm to 1.4 ppm in the feedwater.
ETA had proven to have superior distribution characteristics relative to ammonia, and thus provided better erosion/corrosion protection in high pressure extraction steam and heater drain lines.
Since October 1993, the licensee used hydrazine at concentrations greater than 100 ppb in the feedwater to ensure stable reducing conditions throughout the secondary system.
The licensee replaced hydrazine with carbohydrazide for a two-month evaluation period (March - April 1995)
because it is a non-hazardous alternative to hydrazine and a more efficient oxygen scavenger and metal passivator than hydrazine, which would yield lower iron transport rates.
The test results were inconclusive and a second trial will be done later in 1996.
The licensee had used boric acid since December 1992 for pH control.
The feedwater pH was maintained at about 8.7 to counter IGA/SCC.
Harris is a high sulfate plant, with SG sulfate concentrations at approximately 5.0 ppb (as compared to the industry average of 1.7 ppb).
This is due to the use of ETA which decomposes at SG operating temperatures, resulting in anion resin fouling and subsequent sulfate leakage.
This situation was resolved with the installation of blowdown demineralizers in August 1995.
They were placed in service for the Fuel Cycle
startup in October 1995.
This.,addition should allow better control of sulfates and allow the ETA concentration in the feedwater to be increased, which, in turn, will result in lower iron transport rates than previously experienced.
The licensee was also reviewing the EPRI guidelines on molar ratio control for applicability at Harris.
The intent of molar ratio control is to avoid the creation of highly caustic or acidic conditions in the flow-restricted areas (crevices) of SGs which could accelerate IGA/SCC of inconel tubing.
The ratio is obtained by dividing concentrations of strong cations, sodium, and potassium by concentrations of strong anions, chlorides, and sulfates.
The latest Harris position on molar ratio control was sodium source reduction via skipped anion polisher regeneration.
Otherwise, plant performance and industry experience would continue to be evaluate.3.2 Sludge Lancing
~
~
Sludge lancing has been carried out during every refueling outage of each unit since plant operations began.
A summary of sludge removed follows.
Harris Slud e Removal Histor Fuel Cycle No.
2
51
SG A
~lbs.
40.5 38.3 29.0 55.8 155.0 22.0 SG B
~lbs.
36.7 46.8 37.0 60.5 82.0 27.0 SG C
~lbs.
40.0 50.5 16.0 46.8 109.0 26.0 Total
~bs.
117.2 135.6 82.0 163.1 346.0 75.0
'Increase due to first full cycle on Boric Acid Treatment.
'Decrease due to full cycle on ETA and higher blowdown flowrates for the cycle.
The licensee attributed these relatively small amounts of sludge to the strict controls implemented in the secondary chemistry program.
5.3.3 Plugged Tubes The inspector reviewed the number of plugged tubes in the SGs to date.
The following table summarizes the tube plugging history at Harris.
Harris Tube Plu in Histor Refueling Outage SG A SG B
SG C
Total No.
~tubes
~tubes
~tubes
~tubes PSI
2 FO
4
6 Total ll
3
4
3ll
9
,46 This number represented 0.33 percent of the original tubes available prior to initial plant startup, and left 13688 tubes in service.
The licensee attributed these relatively small numbers of plugged tubes to the strict controls implemented in the secondary chemistry progra.3.4 Because of the good performance of the SGs as reflected by the low amounts of sludge removed and small number of plugged tubes, the licensee had no immediate plans for a chemical cleaning of the SGs.
System Parameters TS 3/4.7. 1.4 specified that the specific activity of the secondary coolant be limited to less than or equal to 0. 1 pCi/ml DEI.
TS 3.4.6.2.c required primary to secondary leakage to be less than 0.35 gallons per minute.
Secondary chemistry procedures limited sulfate and
.
sodium concentrations to less than 20 ppb to prevent from-being in Action Level 1.
Pursuant to these requirements, the inspector reviewed summaries for these parameters for the arbitrarily-chosen period of November 1,
1995 through January 18, 1996.
All of the reviewed parameters were well within specified limits.
The inspector concluded that the licensee had taken proactive steps to preserve/protect its SGs through effective implementation of its Secondary Water Chemistry Program.
The licensee had implemented an effective overall chemistry program to not only maintain the components of both the primary and secondary systems, but to reduce the potential dose to its personnel.
t No violations or deviations were identified.
5.4 Observation of Liquid Effluent Release The inspector reviewed licensee activities involved in making a liquid release (release number 960005.002.003.L)
from the Treated Laundry and Hot Shower
"B" Tank.
The inspector reviewed selected portions of chemistry and radiochemistry procedure CRC-265, Revision 5, Chemistry Control of the Laundry and Hot Shower, Chemical Drains, and Floor Drains Waste Treatment System; radiochemistry procedure RCP-660, Revision.8, Sample Preparation for Determination of Radioactivity; and CRC-851, Revision 7, ODCM Software Instructions and Documentation.
The inspector observed a licensee technician obtain a liquid grab sample from the sampling panel, return it to the laboratory for pH determination and preparation for radioactivity analysis, take it to the count room for analysis, and generate the release permit after the analysis determined that actftity levels were acceptable for release.
The inspector noted that the technician was knowledgeable, used proper sampling techniques and good health physics practices, and followed the procedures closely.
The inspector observed the operators begin the release and noted that they closely followed procedure OP-120. 10.04, Revision 9, Treated Laundry and Hot Shower Tanks.
The release went smoothly.
Based upon the above activities, the inspector concluded that the licensee's program for making liquid waste releases was being effectively implemented and that procedural requirements were satisfied.
No violations or deviations were identifie.5 Semiannual Radioactive Effluent Release Report Prior to Nay 1995, TS 6.9. 1.4 required the licensee to submit a
Radioactive Effluent Release Report within two months after the specified reporting period covering the operation of the facility during the previous six months of operation.
The inspector previously reviewed the reported results of the semiannual radioactive effluent release reports for both halves of 1994 during the
,
inspection documented in NRC IR 400/95-09, paragraph 5.
However, the results of the hypothetical maximum yearly dose estimates to a member of the public (located at the site)
boundary from radioactive materials in gaseous and liquid effluents released during 1994 (as reported in the Semiannual Radioactive Effluent Release Report)
were erroneous.
In compiling the information in tabular form for IR 400/95-09, the inspector noted that the licensee had reported identical values in 1993 and 1994 for beta and gamma air doses.
A subsequent telephone call with the licensee determined that the information presented in the 1994 report was incorrect.
Hence, the values used in the IR 400/95-09 table reflected accurate values verbally reported to the inspector by the licensee.
The licensee issued an addendum to the 1994 report which corrected the erroneous information.
The corrected data differed slightly from those verbally reported to the inspector and printed in NRC IR 400/95-09.
A comparison of the different values follows:
Shearon Harris Nuclear Power Plant Cumulative Estimated Doses from Effluents for 1994 IR Values Addendum Annual Values
~Lmit Airborne Gamma Air Dose (mrad)
Beta Air Dose (mrad)
Critical Organ Dose (mrem)
Liquid Total Body Dose (mrem)
Critical Organ Dose (Liver)(mrem)
3.49E-2 8.02E-2 6. 71E-2 2. 51E-1 3.16E-1 3.49E-2 8.11E-2 6.71E-2 2.46E-1 3.12E-1
20
'
The release of radioactive material to the environment from Harris for 1994 was a small fraction of the
CFR 20, Appendix B and
CFR 50, Appendix I limits.
As can be seen from the data presented above, the annual calculated dose contributions to the hypothetical maximum-exposed individual from the.radionuclides in liquid and gaseous effluent released to unrestricted areas were all less than four percent of the limits specified in the ODCN, even when the amended values were considere No violations or deviations were identified.
5.6 5.6.1 Radiological Environmental Honitoring Program (REHP)
TS 3/4. 12. 1 specified that the licensee shall conduct a
REHP to monitor radiation and radionuclides in the environs of the plant and define how the program shall be conducted.
The REHP shall provide representative measurements of radioactivity in the highest potential exposure pathways, verification of the accuracy of the effluent monitoring program, and modeling of environmental exposure pathways.
Accumulation
.
of radioactivity in the environment can thereby be measured and trends can be assessed to determine whether or not the radioactivity resulted from plant operations.
The data can also be used to detect unanticipated pathways for the transport of radionuclides through the environment, as well as project the potential dose to off-site populations based on the cumulative measurements of any plant-originated radioactivity.
The licensee Environmental Honitoring Program is designed to detect any effects of plant operation on environmental radiation levels by monitoring radiation pathways in the area surrounding the plant site.
It also verifies that the measurable concentrations of radioactive materials and levels of radiation are not higher than expected, based on effluent measurements and modeling of the environmental exposure pathways.
Indicator sampling stations are located where detection of the radiological effects of the plant's operation would be most likely, where the collected samples should provide a significant indication of potential dose to man, and where an adequate comparison of predicted radiological levels might be made with measured levels.
Control stations are located where radiological levels are not expected to be significantly influenced by plant operation; i.e., at background locations.
An environmental impact assessment of plant operation is made from the radiological measurements of the sampling stations.
The radiological environmental data as reported in the Annual Radiological Environmental Operating Reports for 1993 and 1994 indicated that plant operations had no significant impact on the environment or public health and safety during that period (see NRC IR 400/95-09, paragraph 6).
Observation of Air Sampling Stations The inspector accompanied a technician to observe the physical condition and operability of the three air sampling stations, including:
API-0014, API-0016, and API-0031.
The stations were co-located with sampling stations of the State of North Carolina.
All air sampling stations were located in areas free of tall weeds/vegetation which might interfere with the collection of.a representative sa'mple.
A TLD was also placed at each of the air sampling stations.
The inspector noted that all of the sampling units were well-maintained and that they had been calibrated within the prescribed frequency.
The inspector noted that the TLDs were properly located and that there was no evidence of vandalis.6.2 The inspector concluded that the licensee's program to maintain its environmental air sampling stations was effective.
Interlaboratory Cross-Check Program The Radiochemistry Laboratory at the Harris Energy and Environmental Center in New Hill, North Carolina, currently provides radioanalytical services for CP8L's nuclear plant radiological environmental surveillance programs.
The laboratory had been a participant in the EPA's cross-check program and had used its performance in the program as..
a major determinant for the accuracy and precision of its own analytical results.
However, the EPA has discontinued its program.
The inspector discussed the licensee's plans for satisfying program requirements and gave the licensee a copy of a letter from NRR which outlined acceptable licensee alternatives in response to an inquiry by the NEI.
The licensee had already contracted with an independent laboratory to provide the required service.
The inspector concluded that the licensee had been proactive in the resolution of finding an alternative to the EPA's cross-check program.
Likewise, the licensee had an effective program in place to monitor radiological effluents and direct radiation due to plant operations.
No violations or deviations were identified.
5.7 Control Room Emergency Ventilation.System Per
CFR 50, Appendix A, Criterion XIX, ljcensees shall assur e that adequate radiation protection be provided to permit access to and occupancy of the control room under accident conditions and for the duration of the accident.
Specifically, operability of the control room emergency ventilation system ensures that 1) the ambient air temperature does not exceed the allowable temperature for continuous duty rating for the equipment and instrumentation cooled by this system and 2) the control room remains habitable for operations personnel during and following all credible accident conditions such that the radiation exposure to personnel occupying the control room is limited to 5 rem or less whole body, or its equivalent.
TS 3.7.6 defines operability requirements for the control room emergency air cleanup systems under the various design scenarios.
TS 4.7.6 sets the surveillance requirements for the system.
The inspector reviewed the previous two surveillance results for the HEPA filter, carbon adsorption banks, positive pressure of I/8" water gauge in the Control Room, and dissipation of 14 kW by the heaters to maintain a relative humidity of less than 70K for both system trains, R-2-1A-SA and R-2-1B-SB.
The tests satisfied their respective TS acceptance criteria and were performed within the required frequencies.
The inspector reviewed FSAR Figure 9.4.1-01, HVAC - Air Flow Diagram, Control Room Reactor Auxiliary Building, which showed the general layout
of the components of the Control Room Air Conditioning System.
The inspector walked down the system, from the air intake to the Conti ol Room, to air exhaust, noting the major components, such as isolation dampers, filter banks, fans, and radiation detectors.
All components were well maintained, with no sign of physical degradation.
The inspector discussed system operation under both normal and emergency conditions with the System Engineer.
The inspector concluded that the licensee had implemented a good program to maintain its control room emergency ventilation system within TS operability requirements.
No violations or deviations were identified.
5.8 Radwaste Volume Reduction The licensee continued to focus attention on radwaste volume reduction.
These efforts were generated through increased vigilance, restrictive practices, new technologies, and new techniques of resin regeneration.
The licensee was tracking the volume of DAW generated by work group (Operations, Haintenance, Chemistry, etc.) with the idea that each group could see its contribution to meeting the overall plant goal and be more sensitive to the issue.
This practice would encourage them to propose alternatives to complete their work while generating less r adwaste than previously for a given task.
For 1995, the licensee gener ated approximately 140 cubic meters of non-outage DAW.
The 1996 goal is 135 cubic meters.
In addition, the licensee worked with its waste processing vendor to develop new processes designed to further reduce waste volume.
These included steam reforming (to process solid radwaste),
catalytic extraction (to process resins),
and tritium extraction.
In 1995, processed and/or buried radwaste totaled approximately 25 cubic meters.
The 1996 goal is 20 cubic meters.
Another factor in the reduction of solid radwaste was the new methods used to extend the life of the demineralizer resins, including the use of polymer additives to which isotopes of transition elements (Co, Nn, Fe, Ni, etc.)
attach and are removed via a series of pre-demineralizer filters.
The resins were also regenerated on a tank-specific basis.
These techniques allowed the licensee to process up to a million gallons of water (a four-fold increase)
before exhausting the resins.
The licensee was trying to reduce inleakage (from HVAC condensation, ground water, spent fuel cask decontamination area, etc.),
which was.processed through the liquid radwaste system.
For 1995, the licensee released 1.8 million gallons, exceeding its goal of 1.6 million gallons.
With efforts to reduce inleakage, the licensee expected to meet its goals of 0.8 million gallons and 0.5 million gallons in 1996 and 1997, respectively.
This reduction of water to be processed would extend the life of the demineralizer resin The following summarizes radwaste shipments for the last five years.
The shipments typically included spent resins, filter sludge, dry compressible waste, and contaminated equipment.
Harris Solid Radwaste Shipments 1991 1992 1993 1994 1995 71.2 The inspector concluded that the licensee was continuing to make a
determined effort to further reduce its volume of radwaste.
Volume (cubic meters)
78.0 65.0 46.6 25.1 A significant reduction was noted from the previous years'esults, indicating that the licensee's continued efforts to minimize radwaste have been successful.
Future goals call for continued further reductions.
No violations or deviations were identified.
5.9 5.9.1 Radioactive Material Transportation
CFR 71.5 (a) requires that each licensee who transfers licensed material outside of the confines of its plant or other place of use, or who delivers licensed material to a carrier for transport, shall comply with the applicable requirements of the regulations appropriate to the mode of transport of the DOT in 49 CFR, Parts 170 through 189.
The licensee's program for the packaging and transportation of radioactive materials, including solid radwaste, was conducted by the Radioactive Waste Shipping Group within the Radiation Protection Branch of the EERC Organization.
Radwaste was processed, packaged, loaded, and documented by the Radioactive Waste Shipping Group.
Pursuant to the DOT requirements, the inspector reviewed the licensee's activities affiliated with these requirements as related to Shipment No.96-004.
This shipment included slightly contaminated protective clothing, hard hats, and miscellaneous equipment being sent to another CP&L nuclear plant for use in an upcoming outage.
Observation of Work in Progress The inspector observed some of the activities associated with the preparation of material and loading it into the Sealand container.
The work proceeded well with each member of the work detail handling his responsibilities in an efficient, professional manner.,
The personnel were conscious of potential radiological material hazards, as evidenced by the use of radiation dose meters and smear samples.
Before the truck left the site, the inspector reviewed the shipment survey records and conducted an independent look at several of the survey points, determining that the survey points were in agreement.
The inspector concluded that the survey was properly done and well documente.9.2 Emergency Telephone Number
CFR 172.604(a)(2)
requires that a person who offers a hazardous material for transport must provide a 24-hour emergency response telephone number for use in the event of an emergency involving the material.
This telephone number must be monitor ed at all times by a person who is either knowledgeable of the hazardous material being shipped and has comprehensive emergency response and incident mitigation information for that material, or has immediate access to a person who possesses such knowledge and information.
In the late afternoon of January 18, while the shipment was in transit, the inspector called the emergency telephone number listed in the shipping manifest.
It was answered by Control Room personnel.
The inspector explained that he was trying to ascertain compliance of 49 CFR 172.604, specifically concerning immediate access to someone with incident mitigation information for Shipment 96-004.
Licensee personnel promptly located the accident mitigation information for the shipment; and satisfactorily answered the inspector's questions concerning potential fires, damaged shipping containers, and evacuation/exclusion areas.
5.9.3 Radwaste Shipping Documentation The inspector reviewed shipping logs for 1995.
The licensee did not classify shipments into any particular category, but kept a
chronological log of all shipments of radioactive materials, including items such as laundered protective clothing, contaminated outage equipment, material to be processed prior to final disposal, and radioactive material destined for final disposal.
The inspector also reviewed the documentation packages for the following radioactive material shipments:
95-014 (LSA dewatered bead resin destined for the disposal facility),95-052 (drums of used HVAC granulated charcoal and condensate polisher resin destined for a processing facility), and 95-081 (contaminated outage equipment destined to another nuclear power plant) for completeness and compliance with the regulations.
The packages documented the shipment and included items such as unique shipment and shipping container numbers, content and volume, total activity, analytical summary and breakdown of isotopes with a half-life greater than five years.
The radiation and contamination survey results were within the limits specified.
The inspector concluded that the licensee's program for processing, transporting, and documenting radioactive materials satisfied regulatory requirements; and that the Radioactive Waste Shipping Group was staffed by competent personnel who effectively implemented the program.
No violations or deviations were identifie LLW Storage Plans The inspector discussed with licensee personnel plans for on-site low level radwaste storage due to the closure of the disposal facility at Barnwell, South Carolina to North Carolina generators of radioactive materials.
The conceptual design (discussed in paragraph 9 of IR 400/95-09)
had been finalized.
However, installation of the storage facility would not begin until such a facility was absolutely necessary.
The licensee had seen such positive results in its efforts to reduce its volume of radwaste that the immediate need to construct a new storage facility was eliminated.
Therefore, the plans were placed on hold, but could be realized in a period of several months once the decision to build was made.
The inspector concluded that the licensee had taken a proactive position in the development of contingency plans to assure adequate on-site low level radwaste storage.
No violations or deviations were identified.
Internal and External Exposure Controls
CFR 20. 1201(a)
requires each licensee to control the occupational dose to individual adults, except for planned special exposures, to the following dose limits: (1)
an annual limit, which is the more limiting of the total effective dose equivalent, being equal to 5 rems, or the sum of the deep-dose equivalent and the committed dose equivalent to any individual organ or tissue other than the lens of the eye, being equal to 50 rems; and (2) the annual limits to the lens of the eye, to the skin, and to the extremities, which are an eye dose equivalent of 15 rems, and a shallow-dose equivalent of 50 rems to the skin or to any extremity.
The inspector reviewed and discussed with licensee representatives external exposures for plant and contractor employees for the full year of 1995 based on year-end records.
These records indicated that there were no personnel exposures which exceeded administrative limits during 1995, nor were any personnel doses near
CFR Part 20 or administrative occupational dose limits.
The licensee reported the following maximum doses for 1995 in Rems:
TEOE 1.641; Skin-SOE 1.641; Extremity 1.641; and Lens-Eye 1.561.
Also, through a review of licensee records, the inspector determined that the highest individual internal exposure in 1995 was 8 mrem, which is a small fraction of administrative and regulatory limits.
Through review of licensee procedures and reported dose information, the inspector concluded the licensee was adequately monitoring and tracking individual occupational radiation exposures in accordance with regulatory requirements.
Ouring observation of activities in the Auxiliary Building, Waste Processing Building, and the Fuel Handling Building, the inspector observed workers wearing personal dosimetry
devices in accordance with licensee procedural requirements.
No concerns were observed.
No violations or deviations were identified.
Area and Personnel Contamination Control The licensee maintained approximately 460,000 square feet (ft ) of floor space as radiologically controlled, excluding the containment.
The licensee's tracking of contaminated floor area has recently changed from. ~
"recoverable areas" to all areas (except containment)
which is different than in the past and makes comparisons to previous actual percentage values invalid.
According to licensee records, at year-end the licensee had achieved a monthly average of 3920 square feet of contaminated floor space.
This compared to a
1995 goal of less than or equal to 6000 square feet.
During 1995, plant contaminated areas were controlled between 3473 square feet and 10,883 square feet.
The inspector concluded that contaminated area contr'ol was good and general housekeeping was very good overall.
Surface contamination appeared to be aggressively controlled at its source.
The inspector observed radiation workers performing self-monitoring using the automatic personnel contamination monitors upon exiting the RCA.
Generally, full compliance with licensee procedures was observed for the numerous workers observed exiting the area.
However, the licensee was experiencing some apparent radon personnel contaminations during the inspection period which were contributing to numerous instances of alarming contamination monitors, In one specific instance, a radiation worker who alarmed the contamination monitor was observed to challenge the monitor at least two more times.
This was contrary to posted procedural limits in the area which required HP to be called for decontamination once the contamination monitor had alarmed twice.
In another instance, a worker was observed by the inspector to alarm the monitor, and return to the RCA in a potentially contaminated condition.
No workers were observed crossing the RCA boundary after having alarmed the personnel contamination monitor as contaminated.
Due to the low safety significance and isolated nature of these poor radiation safety practices, the licensee's prompt corrective action to remind the workers of proper frisking practices was considered adequate.
However, these observations represent an area for improved adherence to licensee personnel contamination controls.
The inspector reviewed the licensee's PCE records.
The licensee documented all personnel contaminations including skin, modesty garments, and personal clothing greater than 100 cpm above background measured with a thin window GN pancake detector.
During 1995 ther e were 177 PCEs of which 122 occurred during RFO-6 and 55 occurred during normal operations.
The site goals for RFO-6 and normal operations wer e 100 and 35, respectively, so PCE goals were slightly exceeded for the year as a whole.
However, PCE trends were favorable from the 226 experienced in 1994. Thirty-three of the 177 PCEs in 1995 were from
"clean areas" which remained an area for improvement.
A review of selected contamination events in detail noted that the licensee's documentation and follow-up was appropriate.
Skin dose assessments were performed when required.
For the reports reviewed, resultant exposures were minor, and no concerns were noted.
Labeling of Radioactive Haterials During tours of the licensee's facility, including the reactor control building, reactor auxiliary building, fuel handling and radioactive waste process buildings, the inspector took independent radiation and contamination surveys (with support from an accompanying HP Technician)
and observed good posting of radioactive material areas and radiation areas.
Of the numerous radioactive material tags observed and independently verified as accurate, one tag on a container of pump parts was inaccurately labeled in that, contrary to a radiation dose rate of
mrem/hr at 30 cm indicated on the rad material tag, the inspector independently surveyed and determined a dose rate of 5 mrem/hr at 30 cm.
However, the inspector determined the tagging error to be an isolated example of low safety significance which the licensee promptly corrected and initiated a
CR for follow-up.
Except for this isolated example, the inspector determined that the licensee's control and labeling of contaminated and radioactive material was adequate.
Program for Maintaining Exposures as Low as Reasonably Achievable
CFR 20. 1101(b) states each licensee shall use, to the extent practicable, procedures and engineering controls based upon sound radiation protection principles to achieve occupational doses and doses to members of the public that are ALARA.
The inspector reviewed and discussed with licensee representatives ALARA program implementation and initiatives for RFO-6 and routine operations for 1995.
For 1995, the site collective dose was 174.04 person-rem, just below the revised annual
"stretch" dose goal of 175 person-rem and well within the original 1995 dose goal of 218 person-rem.
The licensee's list of dose reduction initiatives was substantial and the licensee was making good progress in implementing many of them.
Overall, the inspector observed that the ALARA function was involved in day-to-day activities and had provided an increased focus on routine, operational doses.
The ALARA program was effective in reducing overall collective dose, and was considered a strength to the overall radiation protection program.
No violations or deviations were identified.
Self Assessment Licensee program audits, self-assessments, and appraisals were reviewed to determine the adequacy of identification and corrective action programs for deficiencies or weaknesses related to the control of radiation or radioactive materia CFR 20.1101(c)
requires that the licensee review the radiation protection program content and implementation at least annually.
TS 6.5.4.1 requires audits of the facility to be performed by NAD encompassing conformance of facility operations to the provisions contained within the TS's and applicable license conditions at least once per 12 months.
The TS requirement is currently being satisfied by the NAS section which reports to the Site Vice President.
No assessments'had been conducted in this area since the last NRC inspection (documented in NRC IR 400/95-06).
Therefore, the inspector reviewed the licensee's corrective actions for findings contained in the most recently completed assessment (H-ERC-95-01, Environmental and Radiation Control Program Assessment).
The inspector focused on select corrective actions with respect to timeliness and adequacy and found no discrepancies.
The inspector noted adequate management oversight in the 1995 assessment in that appropriate focus was given to identified findings, proposed corrective actions, and resolution of concerns.
A review of a proposed first quarter 1996 assessment revealed that it was extensive in its coverage with safety significant EKRC program areas captured within its scope.
The inspector reviewed and discussed with licensee representatives the program for identifying and correcting deficiencies in implementing the radiation protection program.
Review of selected CRs and radiation safety violations for 1995 noted that the licensee was appropriately identifying and correcting health physics problem areas, and no trends of safety significant adverse performance were identified.
No violations or deviations were identified.
Emergency Classification The inspector reviewed emergency declaration activities associated with the train derailment discussed in NRC IR 400/95-19.
This review was done to determine if the incident was promptly identified and correctly classified in accordance with the Harris Emergency Plan, emergency plan implementing procedures, and applicable regulatory requirements.
The inspector evaluated licensee actions related to the incident.
The inspector conducted interviews with involved licensee employees and reviewed documentation related to the incident including an indepth root cause analysis prepared by the licensee-.
An Unusual Event was declared and terminated at 5:45 p.m.
on December 14, 1995, after a cask railcar, used by the licensee to transport spent fuel, derailed.
At the time of the incident, the railcar was only carrying an empty spent fuel cask which minimized radiological safety risk as well as any significant hazard to plant personnel.
The initiating condition for the emergency declaration occurred at approximately 2:00 p.m. that day when four of eight wheels of the cask railcar derailed from the track.
This derailment satisfied the licensee's emergency classification logic as specified in Attachment 2 of licensee procedure PEP-101, Revision 8,
Emergency Classification and Initial Emergency Actions.
The attachment listed "Train Derailment within the Exclusion Area Boundary" as an Unusual Event under the "other plant hazards" column in the Unusual Event Matrix.
After reviewing the incident, and discussing it with licensee personnel, the inspector determined that the licensee correctly classified the incident as an Unusual Event in accordance with the Harris Emergency Plan and its implementing plant emergency procedures.
The inspector determined that all required offsite notifications were made in accordance with requirements.
However, the inspector determined that the Unusual Event declaration was not made in a timely manner in that the initiating condition for the emergency declaration occurred at approximately 2:00 p.m.
and the Unusual Event was not declared until 5:45 p.m., or approximately three hours and forty five minutes later.
The control room shift supervisor on duty at the time and who, per licensee procedure, was tasked with correct identification and classification of emergency conditions, was initially notified of the incident at 3:15 p.m. or approximately two and a half hours prior to the time of the declaration of the Unusual Event (according to licensee records).
Management discussions concerning the declaration consumed most of the two and a half hours before the event declaration was made.
Subsection 50.47(b)(4)
and Appendix E of 10 CFR Part 50 require licensees to develop an emergency classification scheme whose purpose is to initiate emergency response actions commensurate with existing plant conditions.
CFR 50.54(q) requires licensees to follow and maintain emergency plans which meet the standards in 10 CFR 50.47(b)
and the requirements of Appendix E.
The Harris Emergency Plan and its implementing procedure, Plant Emergency Procedure PEP-101, require an appropriate emergency declaration if an emergency action level contained therein is exceeded.
Although the above regulations and procedure do not provide an explicit time limit for classifying emergencies, they do imply that classification should be made without delay.
The intent of the regulations governing emergency classification is to ensure that actual emergencies are rapidly identified and that response actions to those emergencies are timely and appropriate.
A recent NRC position on Emergency Preparedness, EPPOS No. 2, Revision 0, dated August 1, 1995, states "if classification is not made promptly, following the availability of indications that an emergency condition exists, the goal of the classification scheme is undermined and the intent of the regulations would not be met."
This EPPOS further clarifies the NRC staff position that a
15 minute goal is a reasonable period of time for assessing and classifying an emergency once indications are available to control room operators that an emergency action level has been exceeded.
Contrary to this position and contrary to 10 CFR 50.54(q),
the licensee made an untimely emergency declaration for the train derailment in that the reasonable time period to classify the emergency was exceeded by 2-3 hours.
The failure to make a timely emergency declaration for the derailment is identified as a violation.
However, due to the low safety
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5.17 5.18 5.19 significance of the violation, and the extensive corrective action and indepth evaluation undertaken by the licensee, this violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy, and is identified as NCV 400/96-01-06:
Failure to Declare an Unusual Event in a Timely Nanner.
Subsequent to the derailment incident, the licensee initiated prompt and extensive corrective actions including a root cause evaluation conducted by the EKRC organization, and an evaluation of the delayed emergency classification conducted, by the Emergency Preparedness organization.
Corrective actions included informing site personnel of the need to notify the Control Room promptly when abnormal events occur at the plant site.
With respect to emergency classification, licensee representative indicated that the EALs, and specifically the Unusual Event Matrix, may require revision to preclude emergency declarations for low safety incidents which do not represent a significant plant hazard.
Plant Housekeeping Conditions The inspectors conducted walk-through inspections of a significant portion of the RAB, observing material condition and housekeeping.
The inspectors noted that the areas that had recently been painted were, with few exceptions, being well maintained.
In areas that had not been recently painted, there appeared to be more litter and areas where the lighting was poor.
The licensee has recently assigned the responsibility of relamping certain plant areas to Operations personnel.
Recent indications have shown improvement in plant lighting overall.
Security Control During this period, the inspectors toured the protected area and noted that the perimeter fence was intact and not compromised by erosion or disrepair.
The fence fabric was secured and barbed wire was properly installed.
Isolation zones were maintained on both sides of the barrier and were free of objects which could shield or conceal an individual.
The inspectors observed various security force shifts perform daily activities, including sear ching personnel and packages entering the protected area by special purpose detectors or by a physical patdown for firearms, explosives and contraband.
Other activities included vehicles being searched, escorted and secured; escorting of visitors; patrols; and compensatory posts.
In conclusion, the inspectors found that selected functions and equipment of the security program complied with requirements.
Fire Protection The inspectors observed fire protection activities, staffing and equipment to verify that fire alarms, extinguishing equipment, actuating controls, fire fighting equipment, emergency equipment, and fire barriers were operable.
During plant tours, the inspector looked for fire hazards.
The inspector concluded that the fire equipment and barriers inspected were in proper physical conditio V
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5.20 6.0 Conclusion - Plant Support All programs reviewed, including radioactive effluents and water chemistry, ALARA, contamination control, security, and fire protection, were adequately implemented.
As a possible result of water chemistry programs, the Harris steam generators are performing well.
Sludge lancing and early boration efforts have been effective.
Radwaste volume reduction efforts have been effective.
The licensee's Control Room Emergency Ventilation System was well-maintained and TS-required surveillances satisfied their respective acceptance. criteria.
Radioactive material shipments were well performed.
The licensee had taken a proactive position in the development of contingency plans to assure adequate on-site low level radwaste storage.
Corrective actions to self assessment findings in the plant support area were good.
Minor examples of poor radiological practices were noted as isolated occurrences.
A Non-Cited Violation was issued for untimely declaration of a NOUE following a train derailment on plant property.
OTHER NRC PERSONNEL ON SITE 7.0 8.0 On January 16-19, 1996, Hr. J.
Brady, Senior Resident Inspector selectee, Harris plant, was on site'or plant familiarization and to discuss issues with plant management and the Acting SRI.
On January
E 23, 1996, Hr. H. Shymlock, Branch Chief, RII, was on site for a plant tour and to discuss issues with plant management and the Acting SRI.
On February
L 2, 1996, Nr. N. Le, Harris Plant Project Manager, NRR, was on site to attend an interim exit meeting, tour the plant, and discuss issues with the NRC inspectors.
SPECIAL FSAR REVIEW
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recent discovery of a licensee operating their facility in a manner contrary to the Final Safety Analysis Report (FSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the FSAR descriptions.
While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the FSAR that related to the areas inspected.
The inspectors verified that the FSAR wording was consistent with the observed plant practices, procedures and/or parameters.
EXIT The inspection scope and findings were summarized on February 13, 1996 by the Acting SRI with those persons indicated by an asterisk in paragraph l.
Interim exits were conducted on January 12 5 19, and February
& 9, 1996.
The inspector described the areas inspected and discussed in detail the inspection results.
A listing of inspection findings is provided.
Proprietary information is not contained in this report.
Dissenting comments were not received from the license ~T e
Item Number VIO 96-01-01 URI 96-01-02 NCV 96-01-03 NCV 96-01-04 NCV 96-01-05 NCV 96-01-06 IFI 94-03-01 VIO 95-18-01 LER 95-012-00 LER 95-014-00 Status Open Open Open/Closed Open/Closed Open/Closed Open/Closed Closed Closed Open Open Descri tioh and Reference Inadequate Corrective Actions for Improper Control of RABEES Doors, paragraph 2.4.
Inadequate Procedure Results in Inoperable RWST Level Channel Being Returned to Service, paragraph 2.6.
Failure to Properly Secure Containment Isolation Valve CP-l, paragraph 2.9.2.
RHR Inoperability During Node 6 Caused By Procedure Error, paragraph 3.3.2.
Failure to Incorporate Response Time Testing Requirements for AFW Flow Control Valves, paragraph 4.8.
Failure to Declare an Unusual Event in a Timely Manner, paragraph 5. 16.
Corrective Actions for ACFR 93-560 Concerning Temporary Modification Renewals not Being Performed, paragraph 4.9.
Failure to Report TS Violation Involving Improper Verification of Offsite Power Availability, paragraph 2.10.
Containment Pre-Entry Purge Valve 1CP-1 Drifted Open During Node 1 Power Operation, paragraph 2.9.2.
Residual Heat Removal System Components Mere Removed From Service as Directed During Testing, While Required for Operability, Resulting in a Technical Specification Violation, paragraph 3. LER LER LER 95-015-00 95-016-00 96-001-00 Open Closed Closed Failure to Identify Engineering Safety Features Response Time Testing Requirements During a Hodification to the Flow Control Valve Circuitry for Hotor Driven Auxiliary Feed Water Pumps, paragraph 4.8.
Unexpected Opening of the "A".
Reactor Trip Breaker During Testing, Constitutes an Unplanned ESF)RPS Actuation, paragraph 3.3.1.
Reactor Auxiliary Building Door Found Blocked Open Resulting in Entry into Technical Specification 3.0.3, paragraph 2.9. 1.
9.0 ACRONYHS ACFR ACI AFW ALARA-ANSI AO CFR Ci Co CPKL CPH CR CVCS DAW DEI DGB DO DOT dpm EAL EKC E&RC EP EPA EPPOS EPRI ESF ESR ESW Adverse Condition and Feedback Report American Concrete Institute Auxiliary Feedwater As Low As Reasonably Achievable American National Standards Institute Auxiliary Operator Code of Federal Regulations curie Cobalt Carolina Power and Light Counts per Hinute Condition Report Chemical and Volume Control System Dry Active Waste, Dose Equivalent Iodine Diesel Generating Building Dissolved Oxygen Department of Transportation Disintegrations Per Hinute Emergency Action Level Environmental and Chemistry Environmental and Radiation Control Emergency Preparedness Environmental Protection Agency Emergency Preparedness Position Electrical Power Research Institute Engineered Safety Feature Engineering Service Request Emergency Service Water
GM gpm HEPA HESS HNP HP HRA HVAC IFI IGA IR ISI IST kW 1lb LER LLW LOCA LSA pCi ml Mn mRad mrem NAD NAS ncpm NCV NED NEI Ni NOUE NRC NRR ODCM OST OWP PCE PCR PCSR PDR PMOP ppb ppm RAB Ethanolamine Iron Federal Energy Regulatory Commission Final Safety Analysis Report Feedwater Isolation Valve gram Geiger-Huller Gallons Per Minute High Efficiency Particulate Air Harris Engineering Services Section Harris Nuclear Project Health Physics High Radiation Area Heating Ventilation and Air Conditioning Inspector Follow-up Item Intergranular Attack Inspection Report Inservice Inspection Inservice Testing kilowatt liter pound Licensee Event Report Low Level Radwaste Loss of Coolant Accident Low Specific Activity micro-Curie (I.OE-6 Ci)
milli-liter Manganese milli-Rad Milli-Roentgen-Equivalent-to-Man Nuclear Assessment Department Nuclear Assessment Section Net Counts Per Minute Non-Cited Violation Nuclear Engineering Department Nuclear Energy Institute Nickel Notice of Unusual Event (Emergency Declaration)
Nuclear Regulatory Commission NRC Office of Nuclear Reactor Regulation Off-site Dose Calculation Manual Operations Surveillance Test (procedure)
Operations Work Procedure Personnel Contamination Events Plant Change Request Permanent Cavity Seal Ring Public Document Room Plant Management Observation Program parts per billion parts per million Reactor Auxiliary Building
RABEES-RC RCA RCT RCS REMP Rev RFO RHR RII RP RPS RTB RWP RWST SCC SDE SG SHNPP-SI SSN SSPS TEDE TLD TM TS URI VIO RAB Emergency Exhaust System Radiation Control Radiologically Controlled Area Radiation Control Technician Reactor Coolant System Radiological Environmental Monitoring Program Revision Refueling Outage Residual Heat Removal (system)
Region II (NRC office)
Radiation Protection Reactor Protection System Reactor Trip Breaker Radiation Work Permit Refueling Water Storage Tank Stress Corrosion Cracking Shallow Dose Equivalent Steam Generator Shearon Harris Nuclear Power Plant Safety Injection Shift Supervisor - Nuclear Solid State Protection System Total Effective Dose Equivalent Thermoluminescent Dosimetry Temporary Modification Technical Specification Unresolved Item Violation (of NRC requirements)
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