IR 05000397/1992003
| ML17289A459 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 03/26/1992 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17289A457 | List: |
| References | |
| 50-397-92-03, 50-397-92-3, NUDOCS 9204140015 | |
| Download: ML17289A459 (30) | |
Text
U.S; NUCLEAR REGULATORY COMMISSION
REGION V
Report No:
Docket No:
License No':
Licensee:
50-397/92-03 50-397 NPF-21 Washington Public Power Supply System P. 0.
Box 968 Richland, WA 99352 Facility Name:
Washington Nuclear Project No.
(WNP-2)
Inspection at:
WNP-2 site near Richland, Washington Inspection Conducted:
January 24 - March 8, 1992 Inspectors:
R.
C. Sorensen, Senior Resident Inspector D. L. Proulx, Resident Inspector Approved by:
Summary:
o nson, ie React Projects Section
2b ate igne Ins ection on Januar
March 8 1992 Ins ection Re ort No. 50-397 92-03 Areas Ins ected:
Routine inspection by the resident inspectors of control room operations, licensee action on previous inspection findings, operational safety verification, surveillance program, maintenance program, licensee event reports, design changes and modifications, new fuel receipt activities, spent fuel pool operations, licensed operator training, special inspection topics, and procedure adherence.
During this inspection, inspection procedures 37700, 41701, 60705, -61726, 62703, 71707, 86700, 90712, 92700, 92701, 92702 and 93702 were used.
Safet Issues Mana ement S stem SIMS Items:
None.
Results:
General Conclusions and S ecific Findin s
Si nificant Safet Matters:
None.
9204140015 920330 PDR ADOCK 05000397
.8 PDR
I j
Summar of Violations and Deviations:
Two violations were identified involving (1) failure to perform an adequate safety evaluation for a test procedure that required a Technical Specifications amendment, and (2) failure to comply with the action statement for an inoperable control rod.
Also, one non-cited violation was noted, involving failure to follow procedures for entering action statements.
t Six open items and seven LERs were closed; three new items were opene l I
I I'I jl I
'1
DETAILS
c t t d
L..Oxsen, Deputy Managing Director V. Parrish, Assistant Managing Director for Operations
- J. Baker, Plant Manager
- L. Harrold, Assistant Plant Manager
- C. NcGilton, Manager, Operational Assur ance
- G. Sorensen, Hanager, Regulatory Programs C. Edwards, guality Control Hanager
- D. Pisarcik, Health Physics and Chemistry Manager
- J. Harmon, Maintenance Manager S.
NcKay, Operations Hanager A. Hosier, Licensing Manager S. Davison, guality Assur ance Manager
- J. Peters, Administrative Manager
- W. Shaeffer, Assistant Operations Manager
- R. Barbee, Plant Engineering Supervisor
- J. Rhoads, Manager, Operational Events Analysis and Correction
- S. Washington, Manager, Nuclear Safety Engineering
- C. Fies, Compliance Engineer The inspectors also interviewed various control room operators, shift supervisors and shift managers, and maintenance, engineering, quality
'ssurance, and management personnel.
- Attended the Exit Meeting on March 10, 1992.
Plant Status At the beginning of the inspection period, the plant was operating at 100X power, and continued to operate at full power until February 21.
On February 21, a sudden increase of about 1.5 GPH unidentified leakage occurred and resulted in the licensee downpowering the plant to about 5%
power to locate the leak.
The leak was located in the flange of the control rod drive mechanism (CRDH) for control rod 42-59.
The hydraulic control unit (HCU) for that CRDH was isolated, which caused the leakage to decrease.
Reactor power was again increased and was at about 92X on February 25 when the licensee declared both trains of the Containment Atmospheric Control (CAC) system inoperable (see paragraph 5).
Technical Specification 3.0.3 was entered and an Unusual Event was declared.
The licensee shut down the plant to redesign and modify the CAC system, as well as to accomplish other forced outage maintenance.
The plant remained in cold shutdown, pending completion of this work, through the
'nd of the inspection period.
Previousl Identified NRC Ins ection Items 92701-92702 The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
Closed 'nresolved Item 397 91-46-01:
Lack of Documentation for Seismic gualification of Diesel Starting Air (DSA) Piping The inspector had reviewed the qualification information document ((ID) file that documented the seismic qualification of the DSA piping for the Division 1 and 2 Emergency Diesel Generators (EDG).
The inspector had walked.down the piping and noticed that the configuration of the. Division
DSA piping differed from the qualified configuration documented in the /ID file.
The inspector had requested the licensee to provide documentation showing that the configuration was seismically qualified.
Cognizant licensee representatives provided documentation to the inspector showing that the configuration was seismically qualified.
A modification to the Division 1 piping had been implemented in 1983 and the new configuration had been requalified at that time.
This was done through the use of span charts for small bore piping.
The span charts showed to what criteria the piping configuration had to be designed in order to be seismically qualified.
These charts were developed as the product of a different type of seismic analysis than the one originally used by the vendor to qualify the DSA piping.
This item is closed.
Closed Violation 397 91-12-01 Emer enc 0 eratin Procedures EOPs in Remote Shutdown Room Did Not Contain All Revisions as
~Re uired The inspector had identified a copy of the EOPs posted on the wall'n the Remote Shutdown Room that did not contain the latest revision.
As. corrective action, the licensee committed to revise procedures to perform a semi-annual audit of the EOPs in all
'locations, and to assign responsibility to the Operations Procedure Coordinator to review and approve all EOP deviations to ensure accuracy.
The inspector reviewed revisions to PPM 1.2.3,
"Use of Controlled Plant Procedures,"
and PPM 1.2.4,
"Plant Procedure Approval, Revision, and Distribution," that fulfilled the above commitment.
This item is closed.
Closed Violation 397 91-12-04 Im ro er Control of Combustible Material Problems had been identified by the inspector with implementation of the fire protection program.
PPM 1.3.10 implements the fire protec-tion program described in the FSAR, as required by Section 6.8. l.g of the Technical Specifications.
PPM 1.3. 10 requires the use of, transient combustible permits to account for increased fire loadings in certain vital areas.
The inspector had noted that no transient combustible permit had been obtained for. two 55 gallon drums of lube oil in the Division I Emergency Diesel Generator (EDG)
Room.
Also, no transient combustible permit had been obtained for a large quantity of transient combustibles in another vital 'are In their response to the Notice of Violation (NOV), the licensee had determined the reasons for the violation and had committed to taking appropriate corrective actions.
These corrective actions included providing specific instruction and direction on the requirements of transient combustible permits to electrical maintenance personnel who prepare Maintenance Work Requests (HWRs).
The inspector reviewed documented evidence of this action.
The,licensee's proposed corrective actions also included providing guidance on fire loading and use of transient combustible permits to personnel involved in the handling and storage of expendable materials.
PPM 1.3. 10 was revised accordingly to provide this guidance.
In addition, a
memo was issued by the plant manager to all plant personnel reminding them of the importance of complying with fire protection requirements.
This item is closed.
Closed Violation 397 91-18-02 - Fire Door Left 0 en Contrar to Fire Protection Pro ram The inspector found an open fire door on the 522'evel of the reactor building with no one in attendance and no fire protection system impairment checklist in effect.
The licensee's proposed corrective action included revising GET training to provide more emphasis on fire protection requirements, especially fire system impairments.
The inspector participated in this training and found
.it to be satisfactory.
Further, the licensee committed to issue a
memo to remind all craft supervisors to obtain proper fire protection permits prior to starting work.
This memorandum was issued in September 1991.
This item is closed.
Closed Violation 397 91-35-04 - Hain Steam Line Drains 0 ened in Mode
PPM 3. 1.2, Reactor Plant Cold Startup, had instructed operators to shut HS-V-16 and HS-V-19, the steam line drains, before passing from
, Mode 4 into Mode 3.
The procedure also stated that the valves were to remain closed until the reactor was shut down and had again entered Mode 4.
These instructions were in place due to.the thermal s'hock considerations of the downstream piping when the valves are cycled during hot plant conditions.
Contrary to these instructions, operators, reopened HS-V-16 and HS-V-19 while the reactor was still in Mode 2, imposing a thermal shock on the downstream piping.
Applicable procedures were revised to allow opening these valves
.intermittently, but requiring documentation of the occurrence in a PER, since'he downstream piping is allowed to experience a limited
, number of thermal cycles.
Revised instructions were provided concerning. the sequence
'in which the valves are to be opened.
This incident was also discussed in the night orders.
Design Engineering was also independently evaluating the thermal fatigue on the downstream piping in order to determine if an infinite number of thermal cycles was acceptable.
This item is close i Ij
~l
Closed Unresolved Item 397 91-46-03 Reactor Protection S stem Related Pressure Transmitters Isolated Without Pro er Controls In discussions with guality Assurance (gA) personnel, the inspector had learned about an occurrence wherein certain pressure switches had been isolated during low power turbine testing.
These pressure switches sense turbine first stage pressure and enable certain reactor protection system (RPS)
scram signals for throttle valve closure and governor valve fast closure.
The pressure switches actuate at about 150 psig turbine first stage pressure, which is normally equivalent to 30X reactor power.
Thus, the RPS trips described above are not in effect until 30X reactor power is achieved due to these pressure switch permissives.
However, isolating them inhibits the RPS trips described above from coming into effect.
Technical Specifications require the above two RPS actuations to be operable in Node 1, but to be automatically bypassed at less than 30X power, which is the function of the pressure switches described above.
The action statement only requires reducing reactor power to
'ess than 30X with these RPS trips inoperable.
During low power -turbine testing, a pressure spike of greater than 150 psig turbine first stage pressure was often experienced when
,turbine control was transferred from the throttle valves (TVs) to the governor valves (GVs),
even though reactor power was typically about 20X.
This would cause a reactor scram to occur due to turbine throttle valves indicating less than full open.
In September 1990, the operations staff precluded this by isolating the pressure switches discussed above without formally entering the action statement or documenting the action in the Shift Nanager's log.
A pressure spike in turbine first stage pressure occurred during the TV/GV transfer, and a reactor scram would have ensued even though reactor power was about 20%.
A PER was written documenting the event, and the issue was further escalated by gA. It was resolved by the licensee by revising PPM 2.5,7 (the turbine operating procedure)
to only allow isolation of the applicable pressure switches with the Plant Nanager's written permission.
The licensee also conducted a formal
CFR 50.59 evaluation of the procedure revision, which they had failed to do when the pressure switches were first isolated.
The inspector reviewed the event and concluded that a procedure violation had occurred in that the action statement had not been formally entered and a
CFR 50.59 evaluation had not been conducted for isolating the pressure switches.
The inspector also concluded that the criteria of 10 CFR 2, Appendix C;Section V.G. 1 were satisfied for a non-cited violation (NCV 397/92-03-01).
However, the inspector pointed out to the licensee that PPN 2.5.7 needed further revising to indicate that an action statement was to be entered when isolating the subject pressure switches.
The licensee agreed to revise the procedure accordingly.
This item is close g.
The following items'were reviewed by the inspector, but the licensee was not ready to close these items at the time of the inspection.
These wil,l be reviewed during a future inspection.
91-04-01 Failure to test standby gas treatment system in accordance with TS requirements 89-43-Ll High pressure core spray system inoperable due to equipment failure 91-04-LO Inadequate fire protection (Thermolag) of Division II safe shutdown cables 91-10-LO Potential inability to isolate primary containment wire separation caused by inadequate work control.
One non-cited violation was noted, as discussed in paragraph 3'.f.
4.
Review of-CAC Rec cle Flow Verification" Test 92702 The licensee prepared Test Procedure (TP) 8.3.230,
"CAC-HR-1B Recycle Flow Verification From Drywell," as part of the corrective actions for enforcement items dealing with the CAC system.
This test procedure was approved for use by the Plant Operations Committee (POC)
on, February 6,
1992.
TP 8.3.230 directed alignment of the CAC system to operate the blowers by taking a suction from the drywell and discharging to the wet-well.
The licensee considered this alignment to be satisfactory during'ower operations because the CAC system was designed to withstand full post-LOCA primary containment pressure, and because the lineup was iden-tical to that in which CAC would operate during a design basis accident.
The licensee intended to perform procedure TP 8.3.230, to verify proper operation of the CAC system, while the plant was in Node
(Power Operation).
The inspector expressed concern that the proposed valve lineup prescribed by the procedure would create a path bypassing the pressure suppression function of the suppression pool.
Although this valve lineup was identical to the lineup described in the FSAR, the FSAR assumes CAC is initiated approximately six hours into a design basis accident scenario, long after the blowdown and pressure suppression portion of the accident have occurred.
FSAR section 6.2. 1. 1.5.4, "Analytical Results,"
states that the maximum allowable bypass leakage capacity, A/K, equals about
.050 square feet,'ccording to the standard review plan.
This corresponds to a
4 inch line size, which is approximately the size of the CAC lines out of the drywell.
However TS 3.6.2. 1 states:
"The suppression chamber shall be OPERABLE with: b. Drywell-to-Suppression chamber bypass leakage less than or equal to IOX of the allowable A/K design value of.050 square feet."
TS 3.6.2. 1 could not have been met during performance of TP 8.3.230 at power, because bypass leakage would have been nearly 0.050 square feet rather than the allowable ION of 0.050 square feet.
Furthermore, the
licensee could not have met the action statement of 3.6.2.
1 which states
"With the drywell-to-suppression chamber bypass in excess of the limit, restore the bypass leakage to within the limit prior to increasing reactor coolant temperature above 200 degrees."
Therefore, in order to perform TP 8.3.230 in Mode 1 the licensee should. have obtained a TS amendment or NRC permission to perform this special CAC test.
The POC approved TP 8.3.230 on February 6,
1992 during POC meeting 92-06. 1, for use in Mode 1.
The POC determined that no unreviewed safety question existed, and did not determine that a TS amendment was required.
On February 11, the resident inspector expressed concern to the Plant Manager about the planned performance of TP 8.3.230 in Mode 1 with a suppression pool bypass path in place.
The procedure was already temporarily on hold due to a different concern from the shift manager, which was eventually resolved.
However, TP 8.3.230 was revised to line up the CAC system solely from and to the drywell, eliminating the suppression pool bypass path.
Had not the inspector raised his concern, the licensee would likely have conducted the procedure as approved.
The fact that the POC approved TP 8.3.230 for performance in Mode 1, with a suppression pool bypass path existing, in apparent violation of the Technical Specifications, is an apparent violation of 10 CFR 50.59.
(Violation 397/92-03-02)
Unusual Event and Reactor Shutdown 93702 On February 25, 1992, the licensee determined that the containment atmospheric control (CAC) system could not be operated simultaneously with suppression pool cooling.
This was due to the CAC system drain being connected to the residual heat removal (RHR) system test return line, which is used for suppression pool cooling.
If these two systems were operated simultaneously, the drain line of the CAC system would back up and flood the CAC motors and blowers, rendering them inoperable.
The suppression pool cooling mode of RHR and the CAC system must be operating at the same time during a design basis accident according to the EOPs and Chapter 6 of the safety analysis report.
Upon this discovery, the licensee declared both trains of CAC inoperable and entered TS action
. statement 3.0.3.
This caused the licensee to declare an unusual event (UE) according to their emergency plan implementation procedures.
The licensee subsequently commenced a reactor shutdown, and exited the UE when the plant was in hot shutdown.
The inspector observed the licensee's performance during the reactor shutdown.
.The licensee reduced power by inserting control rods and by reducing recirculation flow until the reactor was at 20 percent power.
The operators then scrammed the reactor (as prescribed by the shutdown procedure).
After the scram, the operators overfed the reactor pressure, vessel (RPV) until the Level 8 (+54.5 inches) setpoint trip was reached, causing the reactor feed pumps to trip.
The operators reduced reactor pressure to approximately 630 psig, to allow for RPV level control via injection by the condensate booster pumps.
This reactor pressure was apparently too high such that it prevented the condensate booster pumps from injecting.
Therefore, RPV level decreased to approximately
inches, near the Level 3 scram setpoint of 13 inches, and a half-scram
was received.
To recover level, the operators initiated reactor core isolation cooling (RCIC) manually.
After water level was restored to normal, pressure was decreased to approximately 580 psig and injection to the RPV via the condensate booster pumps was confirmed.
Subsequent cooldown of the RPV was satisfactory.
The licensee initiated PER 2-92-153 to document the problems with controlling RPV level.
No violations or deviations were identified.'.
0 erational Safet Verification 71707
tT The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Water Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The following items were observed during the tours:
(1)
0 eratin Lo s
and Records.
Records were reviewed against Technical Specifications and administrative control procedure requirements.
On February 22, 1992, operators inserted and declared control rod 42-59 inoperable, then isolated the hydraulic control unit (HCU) per paragraph 5.4 of PPH 2. 1. 1, "Control Rod Drive Operations."
This procedure directed the user to insert and isolate the HCU for an inoperable control rod in a method that was contrary to the Technical Specifications.
Paragraph 5.4 of PPH 2. 1. 1 did not require the.exhaust water isolation valve to be shut, as is required by TS 3. 1.3. I.b.2.
This condition existed for 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br />.
Technical Specifications section 3.1.3.1.b states, in part:
"With one control rod inoperable; 2. If the 'inoperable control rod(s) is inserted, within one hour, disarm the associated directional control valves either:
a) Elec-
=
trically, or b) Hydraulically, by closing the drive water and exhaust water isolation valves.
Otherwise, be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />."
The fact that the licensee did not meet the conditions of the action statement, in that they did not close the exhaust water isolation valve or shut down within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, appeared to violate the Technical Specifications, Section 3. 1.3. l. This problem was discovered on February 22 by the Assistant Operations Manager, who directed that the operators properly isolate the HCU, then contacted the Operations procedures group to obtain a procedure change so that PPH 2. 1. 1 would properly reflect the TS requirements.
An interoffice memorandum (IOM)
was issued to alert other operators of the discrepancy between-PPH 2.1.1 and the TS.
On March 4, 1992, during a review of the Operations Manager's Night Orders in the control room, the inspector noted an entry, referencing the IOH dated March 1, 1992, that was required reading for the operators.
This IOH discussed problems with PPH 2. 1. 1.
The IOM clearly stated,
"...This is contrary to the Tech Spec requirement to close the exhaust water isolation valve."
This was the first time the inspector became aware of the improper isolation of the HCU for control rod 42-59.
The inspector discussed this entry in the night orders with the Assistant Operati'ons Manager, who was present in the control room at the time.
Although the improper alignment appeared to have minimal safety significance, the inspector questioned why a Problem Evaluation Request (PER)
had not been written to document the problem with PPH 2. 1. 1, because the PER process would require a NonConformance Report (NCR),
a root cause analysis, and a reportability evaluation.
On March 4, the licensee wrote a
PER to address the PPM 2. 1. 1 issues, and subsequently determined this to be a reportable occurrence.
Plant management agreed that without prompting from the
'inspector, a Licensee Event Report apparently would not have been written.
(2)
(3)
(4)
Although this violation of the Technical Specifications was initially identified by the licensee, appropriate corrective action (initiation of a PER)
was not taken, and the required LER would apparently not have been submitted absent the inspector's involvement.
The criteria for a non-cited violation, as defined in Section V.G. I of the Enforcement Policy, were therefore not satisfied.
Accordingly, this issue is cited in the Notice of Violation which accompanies this inspection report.
(Violation 397/92-03-03)
Honitorin Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
Shift Mannin
.
Control room and shift manning were observed for conformance with 10 CFR 50.54.(k),
Technical Specifica-tions, and administrative procedures.
The attentiveness of the operators was observed in the execution of their duties, and the control room was observed to be free of distractions such as non-work related radios and reading materials.
E ui ment Lineu s.
Valves and electrical breakers were veri-fied to be in the position or condition required by Technical Specifications and administrative procedures for the applicable
0'
"l 0,
H
(6)
plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specification limiting conditions for operation were verified by direct observation.
ui ment Ta in
.
Selected equipment, for which tagging requests had.been initiated, =was observed to,verify that tags were in place and the equipment was in the condition specified.
General Plant E ui ment Conditions.
Plant equipment was observed for indications of system leakage, improper lubrication, or other conditions that would prevent the system from fulfillingits functional requirements.
Annunciators were observed to ascertain their status and operability.
Fire Protection.
Fire fighting equipment and controls were observed for conformance with administrative procedures.
Plant Chemistr
.
Chemical analyses and trend results were reviewed for conformance with Technical Specifications and administrative control procedures.
Radiation Protection Controls.
The inspectors periodically observed radiological protection practices to determine whether the li'censee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiation Work Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored, to verify operability and adherence to calibration frequency.
During a tour of the 606'evel of the reactor building, the inspector noted that the dryer/separator pit was posted with
~ the words
"CAUTION, Respiratory Protection Required."
The inspector was concerned that an airborne radioactivity area was not being posted properly in accordance with 10 CFR 20.203.
The licensee subsequently posted the dryer/separator pit as
"CAUTION, Airborne Radioactivity Area," to reflect the posting discussed in 10 CFR 20.203.
However, the licensee stated that the area did not need to be posted as an airborne area because the respirators were required for the area due to the very high levels of loose surface contamination that existed.
Therefore, a high potential existed for airborne radioactivity to be generated in the area upon entry.
This issue was referred to the NRC Region V Reactor Radiological Protection Branch for resolution, and it was determined that as long as the licensee can demonstrate that the area does not presently contain airborne activity, it need not be posted.
During a tour of the Reactor Building the inspector noted licensee personnel that were wearing respirators entering the
~
i 0,
-10-drywell.
However, the drywell was not posted as an airborne radioactivity area.
The inspector was also informed by the HP technician that they did not intend to post the localized area.
The licensee stated that
CFR 20.204 states that caution signs (including airborne radioactivity signs)
are not required if the area contains airborne for less than eight hours, an HP technician is continuously present, and the area is under the licensee's control.
This issue was also referred to the Region V Reactor Radiological Protection Branch for resolution, and it was determined that caution signs do not need to be posted for periods in which it is impractical (e.g., for movement of large items into and out of an area).
On March 4, 1992 the inspector noted that iodine and particu-late air sampler RB-3R, located on the 501 foot level of the reactor building, was in operation but was past its calibration due date of March 1, 1992.
This was brought to the attention of Health Physics personnel, who promptly ensured that a
properly calibrated air sampler was installed at that location.
The licensee stated that more thorough tours by HP personnel or equipment operators should have identified this condition.
(10) Plant Housekee in
.
Plant conditions and material/equipment storage were observed to determine the general state of cleanliness and housekeeping.
Housekeeping in the radio-logically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
(11) ~Securit.'he inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures, that the search equipment at the access control points was opera-tional, that the vital area portals were kept locked and alarmed, and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
En ineered Safet Feature Walkdown Selected engineered safety features (and systems important to safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
Proper lubrication and cooling of major components were also observed for adequacy.
The inspectors also verified that certain system valves were in the required position by both local and remote position indication as applicable.
Accessible portions of the following systems were walked down on the indicated date I
f
~Sstem-Diesel-Generator Systems, Divisions I, 2,. and 3.
Hydrogen Recombiners Scram Discharge Volume System l.
Standby Service Water System Dates February
February
,March
February
One violation was noted, as discussed in paragraph 6.b(l) above.
e aration for Refuelin New Fuel Recei t 60 05 The inspector monitored the licensee's preparations for the upcoming refueling outage concerning receipt, inspection, and storage of the new fuel.
The following licensee procedures were reviewed for technical adequacy and were found to be satisfactory.
They were then used as guidelines for the inspection:
Procedure Title PPH 6.2.1 Receipt of New Fuel and Shipping Truck to Bay Activities PPH 6.2.2 New Fuel Handling, Railroad Bay to Refuel Floor Activities PPH 6.2.3 PPM 6.2.4 PPH 6.2.5 New Fuel Handling on the Refueling Floor New Fuel Inspection New Channel Preparation, Inspection, and Installation on New Fuel The inspector periodically monitored the licensee's performance of these procedures such that, in total, over several fuel shipments, all of the sections of the above procedures were covered.
It appeared that the licensee performed these evolutions in a deliberate and formal manner, closely following the checklists, procedures, and precautions of the procedures.
The inspector verified that the required instruments were in calibration and were operating properly, and that the operational checks required by the TS were completed satisfactorily.
The licensee has substantially corrected previous deficiencies that several years prior to this time had led to the dropping of two fuel assemblies.
Licensee procedures contain numerous checklists that were followed closely, and the crane operators themselves appeared to be sensitive to this issue and exhibited careful and conservative operation.
In addition, redundant restraints were provided each step of the way to preclude a repeat even O,i
'1
k
-12-During the fuel channelling process, the licensee discovered that some tie rods of the fuel bundles were moving out of their locked position as the channels were put in place.
This was determined to be a significant finding, because the licensee had already placed a large number of fuel bundles in the core and spent fuel pool that were channelled by the same process.
In addition, many other licensees have employed this same method for fuel channelling.
Siemens (the fuel vendor) provided the licensee an evaluation stating that the fuel in the core was satis-factory, because the tie-rod deficiency would not affect fuel safety margins and,the fuel bundle would still be adequately supported by the other tie rods, and because fuel pin growth due to neutron bombardment would tend to lock the tie rods back in place.
However, the licensee stated that they would add a step to the fuel receipt procedures to reinspect the top of the fuel bundles following channelling, and that they would inspect all of the new fuel previously accepted by the Supply System that was already in the spent fuel pool.
Any deficiencies noted would be corrected.
Although the performance of the licensee's staff regarding the actual movement, inspection, channelling, and storage of the new fuel appeared to be satisfactory, the inspector noted the following deficiencies associated with health physics (HP) practices during these evolutions:
The inspector and a few other licensee personnel received contamination on their shoes as a result of activities on the refueling floor.
Discussions with the HP/Chemistry manager revealed that the overhead crane area was apparently contaminated, and any movement of the overhead crane would result in isolated areas of loose surface contamination on the 606'loor area.
The licensee committed to a full decontamination of the 606'verhead area following the R-8 refueling outage, and also to provide for frequent decontamination (i.e. mopping) of the refueling floor during any overhead crane operations until then.
Several licensee personnel were noted to have improperly taped the legs of their coveralls to their booties.
The portal monitor in use had not been source checked for two days.
Several persons did not tape the velcro center of their coveralls.
Personnel reached across the contamination boundary from the clean side to retrieve the jib crane controls (on several occasions),
with no PCs on.
Personnel partially stepped inside the contaminated zone with no protection.
These deficiencies were discussed with the HP/Chemistry Manager, who stated that the Supply System would continue to emphasize good HP practices and compliance with HP procedures to the entire plant staff.
In addition, new copies of the pictures depicting the dressing and undressing sequences were obtained by the licensee to be placed in the appropriate area No violations or deviations were identified.
8.
Surveillance Testin 61726
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~
~
~
~
~
a.
Surveillance tests req b.
uired to be performed.by the Technical Specsfscatsons (TS) were reviewed on a sampling basis to verify that:
(1)
a technically adequate procedure existed for performance of the surveillance.tests; (2), the surveillance tests had been performed at the frequency specified in the TS and in accordance with the TS surveillance requirements; and -(3) test results satisfied acceptance criteria or wer e properly dispositioned.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
Procedure Descri tion Dates Performed
.
7.4.6.2. 1. 1 Suppression Pool Temperature Non-January
itoring Channel Functional Test 7.1.1 7.4.1.4.1.2 Health Physics/Chemistry Shift Channel Checks Health Physics/Chemistry Daily Channel Checks Rod Worth Minimizer Channel Checks Prior to Shutdown February
February
February
7.4.3. 1. 17 Scram Discharge Volume Level Reactor Protection System Actuation Channel Functional Test.
February
No violations or deviations were identified.
9.
Plant Haintenance 62703 During the inspection period, the inspector observed and reviewed.
documentation associated with maintenance and problem investigation activities to verify compliance with regulatory 'requirements and with administrative and maintenance procedures, required gA/gC involvement, proper use of clearance tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified reportability for these activities was correct.
The inspector witnessed portions of the following maintenance activities:
Descri tion Dates Performed AR 6641, Troubleshoot Diesel Driven January
Air Compressor for HPCS DG Diesel Starting Air
-14-AR 7076, Replace Motor and Refurbish February
Coupling and Shaft for DLO-P-2BI AR 7008, Repair CAC-V-64 February
AR 7834, Fabricate and Install Vent March
Line on the CAC "A" Train Scrubber Piping No violations or deviations were identified.
10.
Simulator Observations 41701 On February 21, the inspector observed the "A" shift crew's simulator
.
preparation for the Operational Evaluation that was to take place on February 27.
One scenario that the inspector observed appeared to be quite difficult and challenging.
This scenario involved an anticipated transient without scram (ATWS) that required intentional lowering of reactor vessel level to mitigate the ATWS, then a subsequent large break loss of coolant accident (LOCA).
The crew failed this scenario because they failed to isolate the main steam lines after the LOCA.
The instructors appeared to be objective and appropriately critical of the crew's performance, and retrained them to ensure that the crew's errors would not be repeated.
The crew subsequently passed the Operational Evaluation on February 27.
No violations or deviations were identified.
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Desi n Chan es and Modifications 37700 The inspector reviewed the following Basic Design Change (BDC) packages:
Modification No.
Descri tion BDC 92-0056-OA BDC 92-0026-OA Rerouting of RHR Return Lines from Recombiner Skids FPC-RO-5 Orifice Replacement The inspector's review consisted of: (1) verifying that the attached safety evaluations per
CFR 50.59 were properly documented and did not result in an unreviewed safety question, (2) performing a walkdown of the associated piping and, (3) verifying that the as-built drawings of.the systems were amended.
The inspector determined that these design changes appeared to be thorough and technically adequate.
No violations or deviations were identified.
12.
Licensee Event Re ort LER Followu 90712 92700 The following LERs were reviewed by the inspectors.
Based on the infor-mation provided in the reports it was concluded that reporting require-ments had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are considered close LER NUMBER DESCRIPTION 92-01 92-03 91-36 91-36-01 High Pressure Core Spray (HPCS) Inoperable Due to HPCS Battery Inoperability Containment Atmosphere Control System Problems Missed ASME Section XI Surveillance Missed ASME Section XI Surveillance 92-04 Scram Discharge Volume Level Switches Not Tested Post Scram as Required In addition, corrective actions for the following LERs were reviewed and verified.
a.
Closed 91-17 - Auto Start of EDGs While on Backfeed - Loss of All 500 KV Electrical Power A disturbance on a 500 KV line into the Ashe substation caused a
loss of all 500 KV lines servicing WNP-2.
Due to the switch alignment in the Ashe substation, the transfer of house loads to transformer TR-S did not occur.
The EDGs started and supplied power
.to vital loads.
The switch alignment in the Ashe substation was incorrect in that a disturbance on one incoming line should not have caused the loss of all 500 KV feeding the Ashe substation.
Since the -Bonneville Power Administration (BPA) is responsible for the offsite power distribution grid, they conducted a root cause investigation into the event.
It was found that activities resulting in the mispositioning of switches had not been properly logged and that operator tours of the substation had not detected the mispositioned switches for 18 days prior to the event.
BPA committed to the licensee to implement corrective actions addressing personnel performance issues and equipment. design inadequacies as follows:
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Counselling of all operators at the Ashe substation on a one-to-one basis about the incident.
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The operator responsible for the mispositioned switch was subjected to disciplinary action.
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Adding annunciation to the Ashe control room to alert operators to off-normal relay selector switch positioning used for maintenance or testing.
Any change of state'f these selector switches will also be automatically recorded through a new link to the events logger.
The relay selector switch handles themselves have been human factors color coded to facilitate visual determination that the switch is in the correct positio II
/
-16-The above design changes were implemented for every relay selector switch associated with 500 KV lines into the Ashe substation.
The licensee provided documentation to the inspector that'howed that these corrective actions were complete.
b.
Closed 91-20 - Certain RHR Train "B" Valves Not 0 erable Under All endix R
Re uirements The licensee had determined that the control circuitry for certain Train "B" RHR valves was configured incorrectly in that the valves may not remain operable in the event of a control room fire.
The licensee rewired the control circuitry per Plant Modification Record (PMR) 91-0287.
All 15 MWRs that implemented PMR 91-0287 were-completed and closed in December 1991.
No violations or deviations were identified.
13.=
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable items, violations or deviations.
An unresolved item addressed during this inspection is discussed in paragraph 3 of this report.
14.
~Ei II The inspectors met with licensee management representatives periodically during the report period to discuss inspection status, and an exit meeting was conducted with the indicated personnel (refer to paragraph 1)
on March 10, 1992.
The scope of the inspection and the inspectors'indings, as noted in this report, were discussed with and acknowledged by the licensee representatives.
The licensee did not identify as proprietary any of the information reviewed by or discussed with the inspectors during the inspectio ~
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