IR 05000259/1992017
| ML18036A747 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 06/02/1992 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18036A746 | List: |
| References | |
| 50-259-92-17, 50-260-92-17, 50-296-92-17, NUDOCS 9206230197 | |
| Download: ML18036A747 (34) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION RE G ION I I 101 MARIETTASTREET, N.W.
ATLANTA,G EORGIA 30323 Report Nos.:
50-259/92-17, 50-260/92-17, and 50-296/92-17 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.:
50-259, 50-260, and 50-296 License Nos.:
DRP-33, DPR-52, and DPR-68 Facility Name:
Browns Ferry Units 1, 2, and 3 Inspection at Browns Ferry Site near Decatur, Alabama Inspection Conducted: April 18 - May 15, 1992 t
Inspector:
C. A. Patter ector D te igned Accompanied by:
E. Christnot, Resident Inspector W. Bearden, Resident Inspector Approved by:
eactor r je ts, Section 4A Division of Reactor Projects Da S'gned SUMMARY Scope:
This routine resident inspection included surveillance observation, maintenance observation, operational safety verification, Unit 1 activities, Unit 3 activities, reportable occurrences, and action on previous inspection findings.
920b2301'P7 920b03 PDR AoaCX 0S0002S9
One hour of backshift coverage was routinely worked during the work week.
Deep backshift inspections were conducted on April 19, April 25, May 2, and May 9, 1992.
Unit two tripped on April 27, 1992, due to failure of the master feedwater water level controller, paragraph four. The licensee conducted a thorough assessment of the trip before restarting the unit on April 28, 1992.
The Unit had been on line for 16 days at the end of the report period.
An unplanned Group 6 isolation occurred on May 5, 1992, due to failure to follow a surveillance instruction and perform independent verification, paragraph four. A radiation monitor handswitch was placed to test and the isolation occurred.
Jumpers had been installed on a different monitor than the one being manipulated.
This is another example of violation 260/92-11-01, concerning independent verification. The response to the violation will address correction action for independent vertification.
Unit 3 revised the Level II Schedule to include the walkdown data.
Fuel load was moved back several months to November 6, 1993.
Work activities are progressing with cooling tower refurbishment, condenser retubing, control room design review, and piping replacement preparations.
One non-cited violation was identified for failure to sign onto a hold order, paragraph six.
Work was performed on a Unit 3 drywell blower without the supervisor signature on the hold order as required by plant procedure.
The hold order was in place but the hold order procedure was not followed. This was identified by Unit 3 operations personnel.
The licensee took prompt corrective action that included interviewing all supervisors allowed to sign onto hold orders and disciplinary personnel action.
One inspector followup item was identified concerning referencing work plan documents to drawing change authorization and electrical
" cable reels, paragraph six. -The inspector identified that cable reels were not labeled to identify the associated work plan that installs the cable.
Difficultywas experienced by the licensee in closing drawing change authorizations because the work plan that implemented the change was not referenced.
The licensee initiated action to address each of these concern REPORT DETAILS Persons Contacted Licensee Employees:
O. Zeringue, Vice President, Browns Ferry Operations
"H. McCluskey, Vice President, Browns Ferry Restart
"J. Scalice, Plant Manager J. Rupert, Engineering and Modifications Manager
.
"J. Swindell, Restart Manager
"M. Herrell, Operations Manager
"J. Maddox, Project Engineer
"M. Bajestani, Technical Support Manager R. Jones, Operations Superintendent A. Sorrell, Special Programs Manager
"C. Crane, Maintenance Manager G. Turner, Site Quality Assurance Manager R. Baron, Site Licensing Manager
"J: McCarthy, Unit 3 Licensing
"P. Salas, Compliance Supervisor
"J. Corey, Site Radiological Control Manager
"A. Brittain, Site Security Manager Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, and public safety officers; and quality assurance, design, and engineering personnel.
NRC Personnel:
P. Kellogg, Section Chief
"C. Patterson, Senior Resident Inspector
"E. Christnot, Resident Inspector
"W. Bearden, Resident Inspector A management meeting was conducted at the site on May 7, 1992, to review the project status.
NRC attendees were S. Ebneter, Region II Regional Administrator; J. Partlow, Associate Director for Projects, NRR; P. Kellogg, Section Chief; F. Hebdon, Project Directorate; and J. Williams, Project Manager.
"Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap.
Surveillance Observation (40500, 61726)
The inspectors observed and/or reviewed the performance of required Sls.
The inspections included reviews of the Sls for technical adequacy and conformance to TS, verification of test instrument calibration, observations of the conduct of testing, confirmation of proper removal from service and return to service of systems, and reviews of test data.
The inspectors also verified that LCOs were met, testing was accomplished by qualified personnel, and the Sls were completed within the required frequency.
The following Sls were reviewed during this reporting period:
a.
2-SI-4.2.8-39A(l), Core Spray System Logic Functional Test Loop I.
This Sl performs logic system functional testing to verify conformance of the CS system loop I logic with operability requirements specified in TS section 4.2.8.
Additionally, the Sl satisfies simulated automatic actuation testing requirements of TS section 4.5.A.1.a for this loop of the CS system.
The inspector observed portions of testing performed on April 30, 1992, including breaker operations at the "2C" CS pump breaker at the 8 4160v shutdown board.
The inspector reviewed the Sl package after completion.
The inspector noted that this was a validation performance of a recently revised procedure.
One problem was identified during the testing in that the unit operator inadvertently operated the "2A" RHR pump handswitch during step 7.79 of the test instead of the "2C" CS handswitch as stated in the Sl ~ This resulted in the actual starting of the RHR pump since it's associated 4160v breaker was not racked out to the test position as the CS pump breakers had been.
The error was immediately identified by the UO and proper operating parameters for the RHR Pump were verified prior to securing the pump.
This misoperation appeared to be due to lack of attention to detail by the UO. This event was discussed with licensee management.
During this discussion the inspector was informed that the individual involved in this event was counseled in accordance with TVA's personnel policy. The topic was included in the licensee's ongoing customer focus training with stressing the need for self-checking.
The inspector determined that this misoperation of the RHR pump handswitch was an isolated case and that the licensee
-"had taken'appropriate corrective actions.
b.
2-SI-4.2.8-5(B), Core Standby Cooling Systems-HPCI, LPCI, Core Spray Initiation High Drywell Pressure Instrument Channel 8 Calibratio This Sl checks the calibration of the core standby cooling systems in order to partially satisfy calibration requirements of TS 3.2.B and 4.2.B for the drywell high pressure function. This Sl was performed on April 6, 1992, as post maintenance testing associated with replacement of pressure transmitter, 2-PT-64-58B, under WO 91-27777-00.
The inspector reviewed the completed Sl package.
No problems were identified with the testing.
2-SI-4.2.B-44(A), ADS Logic System Functional Test-Bus A, Time Delay Relay Calibration, and Bus Power Monitor Test.
This Sl is intended to satisfy requirements in TS table 4.2.B for logic system functional testing of ADS. This Sl tests all relays and contacts of logic circuit to ensure all components operable. This Sl was performed on April 7, 1992, as post maintenance testing associated with replacement of a HFA relay, 2E-K33, under WO 92-51112-00. This relay is located in the "C" main steam line relief valve circuity and was causing problems with the position indication associated with handswitch, 2-HS-1-30A. The inspector reviewed the completed Sl package.
No problems were identified with the testing.
HPCI Isolation On April 23, 1992, at 4:00 a.m., during the performance of the HPCI Steam Line Space High Temperature Functional Test an unexpected Group Four PCIS was received.
All PCIS Group four valves responded as expected, isolating the HPCI system.
The HPCI isolation resulted in declaring HPCI inoperable for about 20 minutes while the system was returned to standby readiness.
The inadvertent isolation was reported to the NRC within four hours of occurrence.
The root cause of the event was determined to be the installation of a test plug 120 degrees out of orientation.
This incorrect installation resulted in the concurrent heating and subsequent actuation of two temperature detectors that satisfied the system logic for HPCI isolation.
In normal test configuration the concurrent heating of two temperature detectors is not possible.
The inspector reviewed the licensee's II and pictures of the test plug.
The test plug could be rotated 120 degrees and installed.
This was a plausible explaination for the unexpected occurrence.
Corrective actions included the orientation marking of the panel plug and receptacles to aid in plug installation; cautions in applicable procedures to ensure plug orientation is considered when installing,
replacement of worn plugs; and review of this report by all operations personnel.
Licensee Self Assessment of Surveillance Instruction Validation Program.
(40500)
The licensee had a history of problems with the procedure validation program.
This with other surveillance problems resulted in an enforcement conference on November 21, 1989.
These problems are discussed in more detail in IR 89-43.
As corrective action TVA committed to various improvements in their procedure upgrade program.
This issue was further reviewed by the NRC and resulted in identification in IR 91-13 of additional concerns associated with inadequate implementation of the Sl validation process.
Specifically 59 Sls had been performed without validation.
Although EA 89-226 was closed in IR 91-21 after the licensee had performed several additional corrective actions, the licensee's QA organization continued to monitor the procedure validation process to assure compliance with various commitments to the NRC for corrective action.
Specifically the decision was made for the QA organization to perform a 100% independent review of the Sl validation process until an adequate baseline for performance could be established.
After establishment of the baseline, periodic monitoring of the process would occur.
The inspector reviewed various licensee QA monitoring and audit reports to determine adequacy of oversight in this area.
A series of QA monitoring reports and followup inspections have been performed by the licensee's onsite QA organization.
The inspector determined that a total of 49 of the original sample population of 457 Sls still required followup on December 1, 1991.
These 49 Sls were the subject of QA Monitoring Report QBF-R-91-0817 which documented QA activities in this area during December 18-19, 1991.
The inspector reviewed that licensee report and determined that the licensee had taken appropriate action for each example.
Of the 49 Sls, 40 were found to have had the validation completed and two Sls were. in progress.-The remaining.7 Sls-were-on administrative hold.
These 7 Sls were not required to support Unit 2 startup or operations and would be addressed prior to restart of their respective units.
An inspector had identified one example of a potential failure by the licensee to perform a Sl validation. The details of this example are discussed in more detail in IR 92-05.
The inspector determined that
the validation had actually been performed but the licensee had failed to include comments resulting from the validation due to inadvertently misfiling the comments with Unit 3 Sls.
The validation was performed again during the next subsequent performance since licensee personnel thought the Sl had not been validated.
The inspector determined that this error was a minor administrative error and an isolated case with no safety significance.
Based on the above review the inspector determined that the licensee has taken appropriate actions to exercise proper oversite in this area.
No violations or deviations were identified in the Surveillance Gbservation area.
Maintenance Observation (62703)
Plant maintenance activities were observed and/or reviewed for selected safety related systems and components to ascertain that they were conducted in accordance with requirements.
The following items were considered during these reviews:
LCOs maintained, use of approved procedures, functional testing and/or calibrations were performed prior to returning components or systems to service, QC records maintained, activities accomplished by qualified personnel, use of properly certified parts and materials, proper use of clearance procedures, and implementation of radiological controls as required.
Work documentation (MR, WR, and WO) were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety related equipment maintenance which might affect plant safety.
The inspectors observed the following maintenance activities during this reporting period:
a.
CCW Pump Refurbishment The inspector observed the maintenance activities for removing Unit 3 CCW pumps for refurbishment.
This involved using a large crane located above underground piping and lifting components over the RHRSW/EECW pumps.
The inspector questioned if the effects of the
-- liftand equipment had.been analyzed for-loading. on the underground piping.
The licensee had prepared DCN S-17560 for the work activities and provided a copy to the inspector.
This DCN was reviewed and referenced calculation CD-00303-921562.
This calculation found the loading on the soil and subterranean components and structure to be
acceptable.
The actual load on the pumping station concrete slab was shown to be less than 400 pounds per square foot maximum allowable load as stated by the BFNP FSAR.
Other restrictions were that no liftshall be performed if a RHRSW or EECW LCO exits, restricted lifts from over Unit 1 and 2 items of the pumping stations, and no lifts near the HPFP.
The inspector noted these restrictions were complied with during the work activities observed.
The inspector concluded the liftactivities had been adequately reviewed by the licensee for structural loading and plant conditions.
"1D" Diesel Generator Outage The inspectors followed the licensee activities associated with a scheduled outage conducted on the 1D DG. The DG was removed from service for performance of several planned work activities.
LCO 0-92-043-3.9.b, which was associated with this outage, was entered on May 12, 1992, at 4:00 am and exited at 1:30 pm on May 13, 1992.
Work was performed under the following:
WO 92-47834, which checked the tightness of bolted connections.
This check is required six months following performance of a six year outage on any diesel generator.
WO 92-50190-00, which replaced ciacked mounting base on the circulating oil pump.
WO 92 51819-00, which tightened the scavenging lube oil pump fasteners to prevent leakage.
WO 92-49051-00, which performed relay calibration on exhaust fan relays.
The inspectors observed portions of work in progress and reviewed the work packages in use at the work locations for the above work
- activities. -The-work packages in use provided adequate detail and instructions to support the intended work activities.
One potential problem that was noted by the inspector was the presence of a DG training manual in the 1D DG Room. This manual was not a licensee controlled document and was labeled as "For Training Only-Not to be Used as a Reference for Maintenance".
The manual was not being used by any of the maintenance personnel during that time present in
the room and the inspector was unable to determine who it belonged to. This issue was discussed with licensee management.
The inspector was informed that the licensee would look into the circumstances associated with this issue.
The inspectors will continue to monitor for any potential inappropriate use of uncontrolled reference material during future inspections.
c.
"18" Main Transformer Replacement The inspectors continued to follow licensee activities associated with replacement of the faulted 18 Main Transformer.
Personnel access into the switchyard was strictly controlled.
The inspectors did not identify any poor work practices during any of the related work. The faulted transformer had been removed from the transformer switchyard and the replacement transformer brought into the yard prior to close of the reporting period.
Final installation and checkout of the replacement transformer is scheduled during the next reporting period.
No violations or deviations were identified in the Maintenance Observation area.
The NRC inspectors followed the overall plant status and any significant safety matters related to plant operations.
Daily discussions were held with plant management and various members of the plant operating staff.
The inspectors made routine visits to the control rooms.
Inspection observations included instrument readings, setpoints and recordings, status of operating systems, status and alignments of emergency standby systems, verification of onsite and offsite power supplies, emergency power sources available for automatic operation, the purpose of temporary tags on equipment controls and switches, annunciator alarm status, adherence to procedures, adherence to LCOs, nuclear instruments operability, temporary alterations in effect, daily journals and logs, stack monitor recorder traces, and control room manning.
This inspection activity also included numerous informal discussions with operators and supervisors.
General plant tours were conducted.
Portions of the turbine buildings, each reactor building, and general plant areas were visited. Observations included valve position and system alignment, snubber and hanger conditions, containment isolation alignments, instrument readings, housekeeping, power supply and breaker alignments, radiation and contaminated area controls, tag controls on equipment, work activities in progress, and radiological
protection controls.
Informal discussions were held with selected plant personnel in their functional areas during these tours.
a.
Unit Status b.
Unit 2 began this report period operating at full power.
The unit tripped on April 27, 1992 which is discussed in this section.
Before the trip, the unit had operated continuously for 57 days.
At the end of the report, the unit had been on line 15 days.
II Plant Trip On April 27, 1992, Unit 2 tripped from 100 percent power due to low reactor water level. The trip was caused by a failure of the master feedwater level controller. The controller output signal dropped from 100 percent to 20 percent that caused all three feed pumps to reduce feedwater flow to the reactor vessel.
The Unit was placed in a stable condition with EHC controlling pressure by the turbine bypass valves and a feed pump used to maintain reactor water level in the normal range.
There were no activities in progress that could have caused electrical interferences in the plant.
Before the trip several momentary level perturbations had occurred.
These were controlled by taking the master feedwater level controller from automatic to manual and stabilizing level.
On April 26, 1992, the licensee replaced the master feedwater level controller with a new one from power stores.
The new controller failed after being energized for a day.
The licensee's troubleshooting of the failed controller found a failed electrolytic capacitor.
The licensee has a program to test capacitors stored as individual items in power stores after the capacitor reach their shelf life. However, no program exists for controllers or other electrical devices that may contain capacitors.
The licensee plans to review this further.
The inspector attended the licensee's PORC meeting on April 28, 1992, to review the trip. The licensee conducted a thorough review of the trip: The'inspector reviewed-chart recorder traces of the trip and did not find any problems with the licensee's assessment.
The reactor was restarted on April 28, 1992, and synchronized to the grid on April 29, 199 c.
Plant Tours Incorrect Lockwiring During a routine tour of the reactor building on May 11, 1992, the inspector identified that an equalizing valve 2-EQ1V-1-9069 on main steam line flow transmitter line B was not correctly lockwired. These valves are locked to prevent inadvertent opening due to vibration or other reasons.
There are four transmitter for each of four main steam lines.
All of the other transmitter equalizing valves were correctly lockwired. The valve handle has two holes drilled in it for lockwiring the handle to the high side and low side isolation valves.
For transmitter 2-PDT-1-25B the equalizing valve was lockwired in tension and reduction of tension could occur as the handle was rotated in the open direction.
For the other 15 valves tension kept the valves closed.
This problem was discussed with the Maintenance Manager.
The inspector reviewed the applicable Sl for calibration of these transmitters, Sl 2.4.2.A-7 (A) and the valve position is second party checked with IV of the valve and seal installed at the end of the procedure.
However, there is no sketch on guidance on how to lockwire the valve. The licensee plans to conduct additional training on lockwiring and review these actions with the inspector.
2)
Phantom Diesel Generator Switch During a routine tour of the Unit 1 and 2 DG rooms on April 29, 1992, the inspector noted that three of four DG raw water pump switchs on the local control stations were not in AUTO.
The switch for the D1 DG was in AUTO but Al, Bl, and C1 were in OFF. The inspector reviewed O-OI-82, Standby Diesel Generator System, Attachment 2B and the raw water pump is specified to be in the AUTO position and IV performed.
.This.was discussed with.the SOS. and it was determined from this discussion that the raw water pump switch was not used.
A plant operator opened one of the local control station cabinets for the inspector and demonstrated that there were no wires connected to the switch. A raw water pump is not supplied with the BFNP DGs.
The source of cooling water for the BFNP DGs is the EECW syste This was discussed with the Operations Manager.
The Operations Manager stated a procedure change would be made to remove the switches from the Ol and the switches removed or labeling changed.
The inspector with licensee representatives observed the material condition of the DG control cabinets.
All cabinets were clean, free of debris, all electrical connections appeared satisfactory, all soldered connections were adequate with no extra solder splashes or overly amounts of.solder, and no potential short circuits were observed.
Unanticipated PCIS Isolation A unplanned Group 6 isolation occurred on May 5, 1992, during performance of 2-SI-4.2.A-10FT, Reactor Building Ventilation Radiation Monitors 2-RM-90-140, 141, 142, 143 Instrument Functional Test.
The event occurred due to inadvertent actuation of 2-RM-90-140, Refuel Zone Radiation Monitor. Steps 7.8.24 and 7.8.25 installed dual shorting jumpers to allow testing 2-Rl-90-141 without receiving an isolation.
However, the instrument technician placed the Operate/Zero/Trip Test handswitch on 2-Rl-90-140 rather than 2-Rl-90-141 in the trip test position during performance of step 7.9.5 of the Sl. This resulted in a common refuel zone isolation and actuation of the SBGT and CREV Systems.
A contributing factor to this failure was the failure of a second individual present at the radiation monitor to verify the proper module prior to proceeding with the testing.
Although step 7.9.5 has provisions for second party verification that verification was not performed prior to performance of the step.
SSP-12.6, Independent Verification, Step 2.3.F, provides specific requirements for performance of second party verification rather than independent verification for actions or activities where incorrect performance would immediately jeopardize the operation of safety systems.
In those cases verification is to be performed prior to the performance of the activity. This failure was due in part to a lack of understanding by maintenance personnel of the difference between independent verification and second party verification. The failure to
- follow SSP-12:6 requirements is considered an additional example of Violation 260/92-11-01 which was issued during the last reporting period.
The response to that violation will address corrective action for implementation of I e.
Inadvertent Plant Evacuation During a tour of the Unit 2 portion of the turbine building conducted by an inspector on April 29, 1992, an announcement was overheard to evacuate the reactor building and turbine building. Within five minutes another announcement was made rescinding the earlier announcement.
When the inspector questioned licensed personnel in the Unit 2 Control Room about the event he was informed that the first announcement had actually originated in the plant simulator located at the licensee's training facility. Phones located in the simulator also have the capability to make plant announcements.
The first announcement had been made by a licensed operator as the normal part of requalification training. The second announcement was made by the Main Control Room after the source of the announcement was determined.
The simulator phones are supposed to be provided with a blocking circuit that normally defeats this function except during infrequent periods when it might be desired (such as during an emergency exercise when the plant simulator is used). Furthermore the inspector learned that this problem had occurred on several occasions during the last few months.
The inspectors met with members of licensee management to discuss this event and that this type event could have serious consequences.
Specifically plant personnel could take various actions resulting from an unintentional announcements including leaving the area of operating equipment or other actions that might result in an inadvertent turbine or reactor trip. The inspectors were informed that the licensee was reviewing this event.
One additional example of a recent violation was identified in the Operational Safety Verification area.
Unit 1 Activities The inspector reviewed and observed the licensee's activities involved with the Unit 1 reactor vessel.
This included reviews of procedures and records; observations of field work, QA/QC, operations and contractor personnel activities; and discussions ~ith licensee and contractor supervisors, engineers, and skilled craft personnel.
The IVVIof the reactor vessel and steam dryer was completed.
Additional activities reviewed included, reactor pressure vessel inspectability study and retrieval of loose material.
The inspector will continue to monitor the Unit 1 reactor vessel activitie.
Unit 3 Restart Activities (30702)
The inspector reviewed and observed the licensee's activities involved with the Unit 3 restart.
This included reviews of procedures, post-job activities, and completed field work; observation of pre-job field work, in-progress field work, and QA/QC activities; attendance at restart craft level, progress meetings, restart program meetings, and management meetings; and periodic discussions with both TVA and contractor personnel, skilled craftsmen, supervisors, managers and executives.
Hold Order Violation On April 15, 1992, the licensee identified that a contractor supervisor did not sign onto a clearance for work performed on a Unit 3 drywell blower.
On March 28, 1992, tags were placed on drywell blower B under hold order 3-92-126.
SSP 12.3, Equipment Clearance Procedure, requires that after a clearance is established that the clearance be issued to personnel on the Approval Clearance List. The licensee conducted an incident investigation, II-B-92-025, of this event and interviewed all of the authorized contractor personnel.
Training had been performed for the personnel.
Two individuals received disciplinary action because of this event.
This violation will not be subject to enforcement because the licensee's effort in identifying and correcting the violation met the criteria specified in Section VII.Bof the Enforcement Policy. This NCV is identified as NCV 296/92-17-01, Failure to Sign Onto a Hold Order.
b.
Pilot/Prototypical Program The inspector observed and reviewed the Unit 3 Pilot/Prototypical program.
The specific areas reviewed were the SPOC and SPAE processes for the cooling towers.
The licensee outlined the SPOC and SPAE in two documents, one titled, Prototypical Plan for Cooling Tower SPAE and the other Prototypical Plan for Cooling Tower Systems Preoperability Checklist, SPOC, Process.
The objective of the SPAE Pilot/Prototypical stated:
The purpose of this prototypical review is to evaluate the System Plant Acceptance Evaluation, SPAE, process, as described in EDPI-4.90-10.
The SPAE process provides verification that all engineering activities required to support a System Pre-Operability Checklist, have been completed.
The SPOC process is controlled by SSP-12.55 and will be evaluated
under a separate prototypical review conducted by TVA. The SPAE process is structured in two phases, similarly to the SPOC process, where Phase I supports a system's Restart Test Program, RTP, testing milestone and Phase 2 supports the system's return to operation, RTO, milestone.
This prototypical review will be conducted on the Cooling Towers, which are being returned to operation, and on other components/systems which are required to support the Cooling Towers.
The SPAE document further stated:
Evaluation of the process will be performed by a joint verification group consisting of Bechtel Quality Engineering, Bechtel Quality Assurance, TVA Restart Engineering, and TVA Quality Assurance.
The group will evaluate the implementation of the process to ensure that the intent of EDPI-4.90-10 and SSP-12.55 is met.
The objective of the SPOC Pilot/Prototypical stated:
The purpose of this procedure is to evaluate the adequacy of the Unit 3 System Pre-Operability Checklist, SPOC, process as designated by Site Standard Practice, SSP,-12.55, for plant cooling towers 1, 5, and 6. This prototypical review evaluates both Phase I and Phase II SPOC processes.
This review deviates from the standard prototypical in that both plant and contractor personnel performance will be evaluated.
The SPOC document further stated:
Actual steps and signatures attesting to the SPOC process can be found on the SPOC forms listed in SSP-12.55.
Multiple concurrence signatures are also listed on these forms.
Quality Assurance will provide quality verification for processes requiring plant as well as contractor performance.
QA will be assisted as necessary by experienced individuals from each affected plant group who will verify the Unit 3 SPOC process-meets the intent of SSP-12.55.
The inspector concluded from this observation and review that the licensee is preparing a Pilot/Prototypical Program for the cooling towers and adequate procedures and processes appear to be in plac Integrated Design Change Notice The inspector reviewed the first integrated DCN and licensee's prototypical review of the process.
This process has been periodically reviewed by the inspector.
The inspector reviewed the DCN, REL, two technical assessments of the process, and final work release approval.
DCN W-17961A was written to replace, reroute, or relocate circuit components.
The REL provides input to the DCN. The REL is a matrix of components to the various programs such as Appendix R, EQ, etc.
Eighteen programs are reviewed to determine the applicable program requirements for the component.
The inspector reviewed the DCN and applicable REL pages.
Each item could be cross-referenced to the DCN and program requirements.
The licensee conducted two technical assessments (EE-0069 and EE-0070).
The assessments were conducted to ascertain the technical adequacy of the DCN.
Each assessment concluded the analysis performed was adequate to demonstrate program integration with respect to breakage identification and proposed resolution.
Problems identified were that the REL was not being maintained per procedure, the scope of the DCN impacts Unit 2 operation although the intent of the DCN was to be non-Unit 2 cycle 6, and lack of documented concurrence by each program that the DCN corrected the identified breakage.
Each item was addressed and closed.
The licensee authorized a work release for the integrated DCN prototypical on April 28, 1992.
The inspector concluded that the licensee did an effective self assessment of the integrated DCN process.
The REL matrix provides a review of components under the various programs necessary for restart of Unit 3.
Construction Activities The major construction activities observed and reviewed by the inspector involved the cooling tower pilot/prototypical return to service.
The reviews consisted of WP writing and closure.
The observations included site. work.activities.
The inspector noted two items during this reporting period.
The first item involved WP closures by SWEC.
The inspector was informed that a difficultywas identified in that some DCAs from a DCN could not be readily tied directly to an implementing WP. This item was discussed with Unit 3 QA Manager, the BFN Engineering, and
Modifications Manager and Unit 3 TVA Restart personnel.
The inspector determined that these activities involve the Pilot/Prototypical Program.
This program was established to identify such problems.
The inspector's concern is that inaccurate status and documentation of modifications was one of the causes for the Browns Ferry shutdown.
The second item noted by the inspector involved electrical cable on reels in the field. During the inspector's reviews for the Unit 2 recovery all cable reels in the field were identified with an IN USE tag.
This tag clearly indicated the work implementing document such as WP or WO for which the electrical cable was to be used.
During recent Unit site field observation several electrical reels were observed as not having the IN USE tag with the work document specified.
The inspector informed licensee management of these items.
This is identified as and IFI 259, 260, 296/92-17-02, Documenting Drawing Change Authorizations and Electrical Cable Installation to Work Documents, due to the problems TVA has experienced with electrical cable installation practices and the accurate tracking of modification status.
Maintenance Activities The major maintenance activities observed and reviewed involved the condenser upgrade program for Unit 3 and the return to service of numbers 1, 5, and 6 cooling towers.
The specific work activities observed were the installation of motors, gear boxes, and fans on the cooling towers and the maintenance support activities associated with the tube pulling. All activities appeared to be controlled by approved work documents.
Pre-Operational Testing/Return to Service Activities The inspector observed and reviewed the initial testing activities involved with the cooling towers return to service.
The activities consisted of running the fans, bumping the liftpump motors, and checking for vibrations." Several problems were identified especially with fan vibration. The test personnel adequately addressed these problems with input from the vendo Unit 3 Schedule On April 27, 1992, an integrated leve! II schedule was issued.
The schedule represents the input taken and analyzed from the various walkdowns.
The schedule was approved by all the project organizations.
Key project milestone dates are as follows:
Target Close Breaker Committed Close Breaker Start Fuel Load Unit 2 Cycle 6 Outage Start Finish Control Room Design Review Start Finish General Electric Recirc.
Safe-End Replacement Start Finish January 23, 1994 March 30, 1994 November.6, 1993 January 29, 1993 April 29, 1993 April 22, 1992 October 23, 1992 IVlay 30, 1992 August 3, 1992 The target date was the analyzed date used for progress tracking, reporting, and internal schedule reviews.
The committed date was the date committed to TVA executive management and the date that shall be utilized as the contractor fee award basis.
Several assumptions were used to develop the schedule.
The first pipe cut to be performed in the plant for RWCU and recirculation system piping replacement program was scheduled for June 1, 1992.
The inspector noted that one assumption was there was no schedule contingency included in the schedule.
The inspectors review of the schedule concluded that all new work items had been identified and included in the schedule.
There was no unknowns in the schedule.
The schedules achievement would depend upon effective implementation of work activities and avoidance of problems.
Unit 2 outage personnel were still reviewing the 90 day cycle 6 outage time and the duration might be extended.
Design Change Notice Rollover Process On April 16, 1992, the inspector reviewed with Unit 3 management the process for taking previously implemented DCNs on Unit 2 to be used for Unit 3. The licensee provided a two page document that gave the evaluation process for evaluation of old ECN's.
The ECNs
are to be evaluated for disposition into six categories.
This ranged from ECNs to be canceled or closed to ECNs that have not been PORC approved,.
The licensee stated the review would involve 119 ECN's of which 46 or 47 may be implemented "as is".
The inspector expressed a concern that some of the old paperwork, although PORC approved may not be still valid. There is still a TS requirement for PORC approval
~ Also, the inspector questioned the lack of formality (i.e. procedural controls) for the rollover process.
In response to this concern, the licensee issued interim order number four to BFEP Pl 89-06, Design Change Control, to formulate the process into an existing plant procedure.
This procedure gives the guidance for when DCNs require safety assessments and PORC approval.
This methodology was presented to NRC on April 21, 1992, and is addressed in PORC minutes 7369.
These actions addressed the inspectors concern regarding the rollover process.
7.
Reportable Occurrences (92700)
The LERs listed below were reviewed to determine if the information provided met NRC requirements.
The determinations included the verification of compliance with TS and regulatory requirements, and addressed the adequacy of the event description, the corrective actions taken, the existence of potential generic problems, compliance with reporting requirements, and the relative safety significance of each event.
Additional in-plant reviews and discussions with plant personnel, as appropriate, were conducted.
(CLOSED) LER 259, 260, 296/9108, Fire Wrap Removed During Unit 3 Integrated Walkdown Activities Without Establishing A Fire Watch This item was discovered by a NRC resident inspector when fire wrap was found removed from electrical junction box associated with operable RHRSW pumps.
No firewatch was in place as required by TS 3.11.6.1.a.
The licensee immediately established a firewatch and work activities stopped until an investigation was completed.
All personnel were retrained on this event and personnel corrective actions taken.
The investigation report was reviewed; and the inspector has routinely followed the licensee's action in this area. These actions addressed the proble.
Action on Previous Inspection Findings (92701, 92702)
a 0 (CLOSED) Violation 259, 260, 296/91-26-02, Fire Wrap Inappropriately Removed The inspector reviewed the licensee's closure package for this item at the same time as LER 259, 260, 296/9108 was reviewed.
The LER is closed in this IR. The VIO response addressed Field Services-Modifications Management problems.
These problems have been corrected.
Additionally, actions were taken to upgrade the work control group and to integrate Unit 3 and Unit 2 activities.
These actions were appropriate at the time of the violation. Additional contractor control problems were identified in IR 92-12.
These concerns will be reviewed when the NOV in IR 92-12 is closed.
b.
(CLOSED) VIO 259,260,296/91-40-01, Failure to Follow Plant Procedures For Control of Electrical Systems This violation was issued with three examples for failure to follow procedure.
The first example involved failure to open the main generator exciter field breaker after the generator output breaker was opened, as required by Operating Instruction 47, Turbine Generator System.
The second involved SDSP 14.9, Equipment Clearance Procedure, which requires that tags will identify as specifically as possible the location of components that are not otherwise uniquely identified.
Failure to followthis procedure resulted in the 4kv shutdown board to transfer from the normal power supply to the alternate when the incorrect panel door was opened.
The third example was for failure to maintain labeling of a drywell blower power supply following a modification.
The licensee responded to this violation by initiating the following corrective actions:
live time training on the event counselling of personnel involved implementation of a design change which automatically opens
. the. main generator exciter..field. breaker. when the turbine is tripped revising SSP 12.3, Equipment Clearance Procedure, to require that an ASOS accompany AUO's when tagging equipment associated with the 4kv shutdown boards placed signs on the 4kv shutdown boards which identify PT fuse locations
I
The inspector reviewed the licensee's closure package, applicable sections of SSP 12.3 and Ol 47, and training records and concluded that corrective actions have been completed that should preclude recurrence of these issues.
No further concerns were identified during review of the licensee actions.
(CLOSED) VIO 259, 260, 296/91-41-02, Inadequate Design Controls for Sub-Contractors Activities.
This item was originally identified when on October 13, 1991, a sub-contractor performing work on a communications system upgrade cut electrical cables to the PREAS readers.
The PREAS readers were used for personnel accountability during a radiological event.
Additional review indicted that the sub-contractor had performed work at the site without adequate documentation.
The inspector reviewed the licensee's response dated, February 7, 1992, in which it was indicated that a formal stop work order was issued by the site quality organization, a CAQR was initiated, and the site communications engineer was provided training. The response also indicated that a new procedure SSP 7.53, Contractor Release/Work Control, would be issued and that all managers would be informed as to the contractors working in their respective organization.
The inspector reviewed procedure 7.53 and noted that the procedure classifies contracts into three classes A, B, and C, with classes A and B affecting plant systems, structures, and components.
The procedure required that for all classes of contracts a Technical Contract Manager be identified in order to over see the contractor activities.
The inspector concluded from this review and observations in the field that the licensee's corrective action was adequate.
(CLOSED) VIO 259,260,296/91-43-02, Failure To Follow Unit Separation Procedure for Personnel Access The licensee did not comply with SSP 12.50, Unit Separation for Recovery Activities, in that contractor personnel assigned to Unit 3 did not have uniquely identified plant access picture badges.
The
- -licensee responded to this violation by re-.emphasizing the Unit 3 identification requirements to plant personnel, revising SSP 12.50 to require that personnel transferring to another onsite organization notify the Plant Access Section so the appropriate badge can be assigned, and on an interim basis posted someone to monitor personnel badges of people as they enter the plant protected are The inspector reviewed corrective actions taken by the licensee, including the revision to the requirements of SSP 12.50 and discussions with various plant personnel, and concluded the licensee has resolved the concerns associated with this violation.
9.
Exit Interview (30703)
The inspection scope and findings were summarized on May 15, 1992, with those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number Descri tion and Reference 259, 260, 296/92-17-01 NCV, Failure to Sign Onto a Hold.
Order, paragraph six.
259, 260, 296/92-17-02 IFI, Documentation Drawing Change Authorization and Electrical Cable Installation to Work Documents, paragraph six.
Licensee management was informed that one LER and four VIOs were closed.
10.
Acronyms and Initialisms'DS ASOS AUO AUTO BFEP BFNP CAQR CCW CS DCA DCN Automatic Depressurization System Assistant Shift Operations Supervisor Auxiliary Unit Operator Automatic Browns-Ferry Engineering Project Browns Ferry Nuclear Plant Condition Adverse to Quality Report Condenser Circulating Water Core Spray Drawing Change Authorization Design Change Notice
DG EA ECN EDPI EHC FSAR HPCI HPFP IFI II IR IVVI LCO LER LPCI MR NCV NRC NRR Ol PCIS PORC PREAS QA QC REL RHR RHRSW/EECW RTO RWCU Sl SOS SPAE SPOC SSP TS UO V
System Emergency Diesel Generator Enforcement Action Engineering Change Notice Engineering Department Instruction Electrical Hydraulic Control Final Safety Analysis Report High Pressure Coolant Injection High Pressure Fire Protection Inspector Followup Item Incident Investigation
Inspection Report
ln Vessel Visual Inspection
Limiting Condition for Operation
Licensee Event Report
Low Pressure Coolant Injection
IVlaintenance Request
Non-cited Violation
Nuclear Regulatory Commission
Nuclear Reactor Regulation
Operating Instruction
Primary Containment Isolation System
Plant Operation Review Committee
Personnel Radiological Accountability
Quality Assurance
Quality Control
Restart Equipment List
Residual Heat Removal Service Water/
Equipment Cooling Water
Return To Operation
Surveillance Instruction
Shift Operations Supervisor
System Plant Acceptance Evaluation
System Pre-Operation Checklist
Site Standard Practice
Technical Specification
Unit Operation
Volt
Violation
Work Order
Work Request