IR 05000397/1989011
| ML17285A583 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 06/09/1989 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17285A582 | List: |
| References | |
| 50-397-89-11, IEB-88-007, IEB-88-7, IEIN-89-010, IEIN-89-10, NUDOCS 8906300018 | |
| Download: ML17285A583 (18) | |
Text
U.S.
NUCLEAR. REGULATORY COMMISSION REGION Y
Report No:
Docket No:
Licensee:
50-397/89-11 50-397 Washington Public Power Supply System P. 0.:Box 968 Richland, WA 99352 Facility Name:
Inspection at:
Washington Nuclear Project No.
2 (WNP-2)
WNP-2 Site near Richland, Washington Inspection Conducted:
March 13 - April 16, 1989 Inspectors:
C.
J.
Bosted, Senior Resident Inspector R,
C.
Sorensen, Resident Inspector Approved by:
Summary:
o nson, ie React Projects Section
ate igne Ins ection on March 13 - A ri1 16, 1989 50-397/89-11
~df<<:
f by b
fd f
room operations, licensee action on previous inspection findings; engineered safety feature (ESF) status, surveillance program, maintenance program,
.
l=icensee event reports, special inspection topics, procedural adherence, and review of periodic reports.
During this inspection, Inspection Procedures 25500, 25599, 30703, 40500, 41701, 61726, 62703, 71707, 71710, 90712, 90713; 92700, 92701 and 92702 were utilized.
Results:
Two non-cited violations (NCVs) were noted and reviewed during this inspec-tion, as discussed further in paragraph 3.e.
Four previously identified items, five LERs, and two Temporary Instruction procedures were closed.
A weakness was observed in the performance of a root cause assessment of the March 11, 1989 rod drift event.
One Unusual Event was declared during this inspection period, as discussed in paragraph 2.
8906300018 8i0< l2 PDR ADOCK 05000397 O
DETAILS Persons Contacted C.
McGilton, Manager, Safety and Assurance
"'C.
Powers, Plant Manager J.
Baker, Assistant Plant Manager
- K.
Cowan, Nuclear Safety Assurance Manager C.
Edwards, Quality Control Manager
- R, Graybeal, Health Physics and Chemistry Manager J.
Harmon, Maintenance Manager A.
Hosier, Licensing Manager D.
Kobus, Quality Assurance Manager
- R.
Koenigs, Technical Manager
- S.
NcKay, Operations Manager
"J.
Peters, Administrative Manager Shaeffer, Assistant Operations Manager R.
Webring, Assistant Maintenance Manager M.
Wuestefeld, Assistant Technical Manager The inspectors also interviewed various control room operators, shift supervisors, shift managers, and maintenance, engineering, quality assurance, and management personnel.
- Attended the Exit. Meeting on April 14, 1989.
Plant Status At the start of the inspection period, the plant was operating at 78$
power.
On March 16, following a review of initial licensing conditions, members of the licensee's engineering staff concluded that the control room ventilation system was not within the bounds of the assumptions used in the control room (post-accident)
dose. assessment analysis.
This placed the plant in an unanalyzed condition; plant management determined that Technical Specification 3.0.3 was applicable, and initiated a plant shutdown.
The engineers calculated that the plant could operate at 52K and be within the design post-accident bounds of the anticipated control room radiation doses.
Power level remained at 524 until another analy-sis was performed and the original calculations were verified on March 22.
Power was raised to 76% after the calculations were performed with more realistic assumptions.
Full power restrictions were removed on March 23, after the licensee carefully reviewed the computer model with General Electric and NRC.
The plant returned to 785 and operated at that power level through the end of the reporting 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)
Enforcement Item (397/87-19-29:
Failure to Comply with Procedures for Proper Installation of E ectrical Terminations.
Several occurrences were identified in which electrical termina-tions (crimping, terminal lugs; or heat shrink tubing) were not performed in accordance with the procedure 10.25.46 "Nodification and Cable Installation".
The licensee denied this violation, but after clarification agreed to update procedure 10.25.19
"Termina-tion and Splicing Instruction" to address examples of acceptable crimp configurations.
The inspector reviewed the preliminary procedure and observed that this procedure has addressed the examples of acceptable crimps and other terminations.
This item is closed.
Closed)
Followu Item 397/87-19-13
- Ineffective Fuel Oil Connections.
The adequacy of the fill locks, the ability to bypass these locks, and the method of sampling the supply fuel were questioned.
The
,inspector questioned the procedure which required a sample bomb
"that opened at the bottom" to sample the fuel oil.
This type of sample bomb-did not exist.
The'icensee's procedure 7.4.8. 1. 1.2.3,
"Diesel Generator Fuel Test",
for obtaining a fuel oil sample does not specify explicitly how to take a fuel oil sample before the fuel is transferred to the storage tank due to the various vendors'ruck arrangements.
The procedure does state that the sample must be obtained and-checked before the oil is transferred.
The inspector also observed the locking arrangement for the fuel oil tank fill connections.
The locks are individual padlocks with chains and appear to be tamper-proof.
Due to the location of the fill connections and the type of effort that appears necessary to defeat the locking arrangement, the inspector concluded that the security of these locks was not now a concern.
This item is closed.
Closed)
Unresolved Item 397/88-37-03
- Insufficient Control of Mechanical Jumpers.
A temporary hose had been connected between a station air compres-sor and the fire protection system to provide cooling water during a modification to the air compressor cooling system.
Caution tags had been installed on the hose, but the hose was not listed on the mechanical jumper log.
The licensee'greed that this hose should be considered to be a mechanical jumper, but plant procedure 1.3.9
"Lifted Leads and Jumpers" did not include this type of mechanical jumper in the definition section of the procedure.
The licensee agreed to update the procedure.
The inspector reviewed the revised procedure and determined that temporary hoses have been included in the the description of mechanical jumpers.
A review of plant temporary hoses indicated that these hoses were properly tagged.
This item is close (Closed)
Undetected Installation Errors in team unne emperature etectors Steam tunnel temperature detectors on two BWR plants were found to have been improperly installed.
These detectors indicate -steam
. leakage in the steam tunnel by monitoring the air temperatures into and out of the air cooling units for the tunnel.
This item had been identified by the licensee and a review was performed by licensee engineers.
The inspector reviewed operating experience report OER 89007A, closed on March 15, 1989, which documented the licensee actions for the review of this information notice.
The report. found that no installation errors exist at WNP-2.
The design was also recently reviewed as part of a Technical Specification setpoint change.
No discrepancies were identified.
This item is closed.
0 en) Unresolved Item 397/89-08-01:
Rod Drift Event On Narch 11, 1989,.a main steam line radiation monitor operated erratically'during two periods about three hours apart.
The erratic performance involved rapid tripping and resetting of the monitor due to a drift in the low voltage inoperable setpoint.
As a result of frequent and/or excessive resetting of the half-scram during the latter period, a brief (about 6 seconds)
low pressure condition was experienced on the scram pilot valve air header.
This low pressure allowed the scram outlet valves to partly open, permitting 34 control rods to drift inward between one and seven notches (one notch equals six inches).
After waiting about
minutes to evaluate local core power distribution, the operating staff reduced recirculation flow to minimum, repositioned control rods, and resumed operation at 75% power..
The licensee performed a root cause analysis (RCA) of this event.
The inspector reviewed a preliminary version during this inspection period, and a final version of the RCA report was reviewed after the close of the report period but before issuance of this inspec-tion report.
A significant input into the RCA report was the Human Performance Evaluation System (HPES) evaluation (attached to the RCA report).
It was noted that the RCA report did not highlight or discuss several key weaknesses involved in the event (some of which were, however discussed in the attached HPES evaluation).
Inspec-tor concerns associated with the RCA included the following:
(1)
Too much time was required for the RCA to be completed.
The event happened on March 11, 1989, and the RCA was not completed and approved until Hay 3.
(2)
The RCA did not highlight the fact that existing procedures gave conflicting and confusing direction on what actions the operators should take following the rod drift even (3)
Although most were discussed in the HPES evaluation, the following human performance issues were not clearly identified in the RCA:
The operator's improperly holding in the scram reset pushbutton (accelerated the loss of scram air header pressure)
The failure of operators to refer to all applicable procedures (e.g.,
the annunciator procedure for rod drift, which called for a reactor scram).
- The delay of 7 minutes before power was reduced to 75K, and a total delay of about 20 minutes before recircu-lation flow (along with reactor power)
was reduced to a minimum.
- The fact that the plant staff had been living with vary-ing pressures on the scram air header (during half-scram conditions)
(4)
The RCA did not discuss whether Technical Specification limits on linear heat generation rate (LHGR) could have been exceeded had the rod drift occurred with the reactor initially at 100'5 power.
(5)
The fact that a plug was found in a vent hole in the pressure reducing valve was not discussed, or its effect on valve per-ormance evaluated.
(6)
The need for maintenance on the scram air header'was not discussed.
(Leaking solenoid and scram valve seals resulted in additional time being required to repressurize the header.
A number of these valves are being reworked during the ongoing refueling outage).
This issue (89-08-01)
remains open pending resolution of the above comments regarding the licensee's RCA.
The HPES evaluation noted that existing procedures did not address the specific plant condition (i.e., multiple rod drifts).
The existing procedure (PPM 4. 1. 1. 1) for Rod Drift addressed only a single rod drifting in.
The licensee corrected this problem by issuing a temporary procedure change on March 13, 1989 to prescribe operator actions in the event of multiple rod drifts.
The failure to have an emergency procedure in effect for multiple rod drifts appears to be in violation of Section 6.8. 1 of the Technical Speci-fications and Section 6 of Regulatory Guide 1.33 (Revision 2),
Appendix A.
The inspector noted that this deficiency had been identified and corrected by the licensee.
Accordingly, this violation is not being cited because the.criteria specified in Section 'V.G of the Enforcement Policy were satisfied.
(NCV 89-11-01, Closed)
The licensee also identified following the event that the operators had not referred to annunciator procedure 4.603.A7-5.7, Rod Drift.
, This procedure included instructions to manually scram the reactor if rods orift in due to low scram air header pressure.
Reactor recirculation flow (and power)
had been reduced to minimum by the time shift personnel referred to this procedure, at which time the licensee determined th'at a scram was no longer appropriate.
Upon further evaluation, the licensee determined that procedures should not require an immediate scram for a multiple rod drift event; this and other related procedures were revised on March 13 to direct a
prompt flow reduction in the event of multiple rod drifts, followed by a manual scram if plant conditions worsen.
However, the opera-tors'ailure,to scram the reactor as directed by the annunciator procedure appears to be a violation of Section 6.8.1 of the Tech-nical Specifications and Section 5 of Regulatory Guide 1.33, Appendix A.
The inspector noted that this deficiency had been identified by the licensee and that appropriate corrective actions had been taken.
Accordingly, this violation is not being cited because the criteria specified in Section V.G of the NRC Enforcement Policy were satisfied.
(NCV 89-11-02, Closed)
~
0 erational Safet Verification 71707 a.
Plant Tours The following plant areas were toured by the inspectors during the course of, the inspection:
Reactor Building Control Room Siesel Generator Building Radwaste Building Service h'ater Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The following items were observed during the tours:
( 1) Operating Logs and Records.
Records were reviewed against Technical Specification and administrative control procedure requirements.
(2)
(3)
Monitoring Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
Shift Manning.
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 material (5)
(6)
(7)
(10)
Equipment Lineups.
Valves and electrical breakers were verified to be in the position or condition required by Technical Specifications and Administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specification limiting conditions for operation were verified by direct observation.
Equipment Tagging.
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 Equipment Conditions.
Plant, equipment was observed for indications of system leakage, improper lubrica-tion, 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 Technical Specifications and administrative procedures.
Plant Chemistry.
Chemical analyses and trend results wer'e reviewed for conformance with Technical Specifications and administrative control procedures.
Radiation Protection Controls.
The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented. in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiation Exposure 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.
Plant Housekeeping.
Plant conditions and material/equipment storage were observed to determine the general state of clean-liness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
Security.
The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plans was in accordance with site procedures, that the search equipment at the access control points was operational, that the, vital area portals were kept locked and
'larmed, and that personnel allowed, access to the protected area were badged and monitored and the monitoring equipment was functiona No violations or deviations were identified.
5.
En ineered Safet Feature S stem Walkdown (71707, 71710 Selected engineered safety feature systems (and systems important to
.
safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
'he inspectors also verified that system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Accessible portions of the following systems were walked down. on the indicated dates.
~Ss tern Diesel Generator Systems, Divisions.1, 2, and 3.
Hydrogen Recombiners Low Pressure Coolant Injection, (LPCI)
Trains "A", "8", and "C" Low Pressure Core Spray (LPCS)
High Pressure Core Spray (HPCS)
Reactor Core Isolation Cooling (RCIC)
Scram Discharge Volume System Standby Liquid Control (SLC) System Standby Service Water System 125V DC Electrical Distribution, Divisions 1 and
250V DC Electrical Distribution No violations or deviations were identified.
6.
Surveillance Testin (61726 Dates March
April 4,
March= 16, April. 10 March 16,
'pril
March 17, April 4 March 16, April 4 March 16, April 4 March 20, April 4 March 20, April 4 March 21, April 13 March 20, April 10 March 20, April 10 a
~
Surveillance tests required to be performed by the Technical Speci-fications (TS) were reviewed on a sampling basis to verify that:
( 1) the surveillance tests were correctly included on the facility schedule; (2)
a technically adequate procedure existed for perfor-
8" ma'nce-of the surveillance tests; (3) the surveillance tests had been performed at the frequency specified in the TS; and (4) test results satisfied acceptance criteria or were properly dispositioned.
b.=
Por.ions of the following surveillance tests were observed by the inspectors on the dates shown:
Procedure 7.4.5.1.11
~0 HPCS Operability Test 7.4.3. 7, 5. 53 Ca 1 ibra tion of Ammeters
&
Voltmeters for 125VDC Div I 7.4.6.5.3.
Standby Gas Treatment Operability Test 7.4.3. 1. 1.56 Main Steam'ine High Rad Channels B
&
D Channel Functional Test (CFT)
7.4.3.2. 1.42 Condenser Vacuum Isolation Channels B&D CFT Dates Performed March
March 20 April 6 April ll April ll 7.4.4.3.1.3 Drywell Sump Flow Monitor CFT April 12 No violations or deviations were identified.
7.
Plant Maintenance (62703)
During the inspection period, the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required gA/gC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectors verified reportability for these activities was correct.
The inspectors witnessed portions of the following maintenance activities:
Descri tion Removal of Spray Pond Sediment per AT 8104 Fire Control Panel Annunciator Window Changeout per AT 0699 Inspection of Spray Pond Pipe Support Anchor Bolts per AT 7914 No violations or deviations were identified.
Dates Performed March 23 April ll April 13
Licensed 0 erator Trainin (41701)
The inspector attended several licensed operator requalification train-ing lectures.. The lectures provided instruction in the revised format for the flow diagrams that implement the actions of the emergency operating procedures (EOPs).
These EOP flow diagrams are used by the Control Room Supervisor to direct the actions of-the operators during abnormal conditions.
The inspector found the discussions in the classroom to be technically correct; however, certain details remained to be worked out in the execution of the flow diagrams.
This was further exemplified during 'simulator training using the flow diagrams, which the inspector observed.
During one simulator scenario with HPCS and RCIC unavailable and reactor pressure vessel (RPV) level decreasing, operators followed the flow dia-gram and began depressurizing the plant to allow low pressure ECCS pumps to inject.
Later, during the critique of the operators'ctions, the instructor indicated 'that the crew should have waited until RPV level reached the top of the active fuel and then emergency depressu-rized.
This would have allowed additional time to try and return HPCS or RCIC back to service.
This indicated to the inspector that some confusion in interpretation and implementation of certain steps of the flow diagram existed.
Also, the inspector noted that additional gui-dance in the conduct of some diagram steps was needed.
For example; the flow diagram did not identify under what conditions the operators should exceed the 100 degree per hour cooldown rate Technical Specification limit.
Later, in discussions with instructors and plant management, they indicated that this initial training in the new EOP format was being concurrently used as a validation process for the accuracy and adequacy of the new approach of casualty control.
The inspector interviewed several licensed operators who indicated that the new format was easier to comprehend and less cumbersome than the former metho'd of implementing EOPs.
The inspector'oted the presence of senior corporate management, but not plant management, during his inspection.
During discussions with plant management, they explained their new procedure for observing ongoing activities, including training.
The inspector discussed the need for more plant management observation of training activities.
No violations or deviations were identified.
(Closed)
TI 2515/99 Ins ection of the Licensee's Im lementation of Re uested ctions of NRC u
eton 88-07 BW
.ower sc>
at)ons 5599 This item was addressed in Inspection Report 88-37 and was left open with one aspect remaining to be resolved.
That aspect was the adequacy of installed instrumentation, specifically LPRMs and APRMs, to detect power oscillations within the core.
General Electric (GE) reviewed its standard Neutron Monitoring System (NMS) design, as normally supplied with BWR designs, and concluded that
it is capable of detecting and displaying neutron flux oscillations at the natural frequency of BWRs (about 0.5 HZ). However, GE determined that additional verification was required if the NNS had been modified by the licensee in such a way that could affect its ability to detect neutron flux oscillations.
Such modifications would include delays or fil'ters added to the instrumentation circuitry.
The licensee. reviewed design changes and field changes affecting the GE-supplied NNS since its original delivery to the site.
This review is documented in licensee memo SS2-PE-88-1162, dated December'2, 1988.
Based on this review, the licensee concluded that no modifications had been made affecting the 0.5 HZ oscillation detection capability of the LPRNs or APRt<s.
This temporary instruction is closed.
Closed)
TI 2515/100 - Pro er Recei t, Stora e, and Handlin of Emer enc Diesel Generator EDG Fuel Oil 255100a The objective of this temporary instruction was to verify that the licensee has a program in place to purchase and store fuel oil that meets Technical Specification requirements.
It contained a list of 15 questions that were to be used to evaluate this program.
The inspector interviewed the system engineer and consulted applicable drawings and procedures to accomplish this evaluation.
The inspector concluded that the licensee's program for fuel oil manage-ment was adequate to ensure the continued operability of the EDGs in accordance with the Technical Specifications.
Further, fuel oil analy-ses are trended as well's filter differential pressures and various fuel pump discharge pressures.
This was considered to be a positive aspect of the program.
However, one drawback was noted.
Unlike the fuel oil,filters, the in-line strainers have no means for monitoring and alarming differential pressures.
They are cleaned yearly and, according to the system engineer, no particulates of any significance have ever been found in the stra1ners as a result of this yearly cleaning.
This temporary instruction is closed.
Review of Cor orate Nuclear Safet Review Board CNSRB ct>vities 40500 The inspector reviewed the activities of the CNSRB to ensure they meet the Technical Specification requirements for composition, meeting fre-quency, records, and review and audit functions.
The executive secre-tary of CNSRB was interviewed and representative records were reviewed to determine compliance with the Technical Specifications.
The inspector reviewed selected CNSRB meeting minutes of meetings conducted over the past year, reviewed several audit reports of audits conducted under the cognizance of the CNSRB, and reviewed the resumes of all CNSRB members and alternates.
The April 1989 CNSRB meeting was cancelled due to absence of some external members.
The inspector plans to attend the next meeting, which is scheduled for July 198 The inspector concluded that the CNSRB was in compliance with Technical Specification requirements.
However, one case was noted wherein the CNSRB missed an opportunity to identify and correct plant problems.
A proposed Technical Specification amendment was reviewed by the CNSRB which later led to the, identification of three violations by the NRC (see Inspection.Report 397/89-04).
This indicated that more diligence and caution was warranted by the CNSRB when reviewing proposed Technical Specification changes by telephone.
This was communicated by the inspector to the CNSRB chairman, who acknowledged the inspector's comments.
No violations or deviations were identified.
12.
Pre aration for Refuelin 60705)
The inspector assessed the adequacy of the licensee's administrative procedures for the control of refueling operations and plant conditions during refueling.
This was to ensure that such procedures exist, and that they are adequate to accomplish the desired objective.
Procedures for the following general areas were reviewed:
PPM 6:3.2 - Fuel Shuffling During Refueling
PPM 10.3.6 - Reactor Vessel Dry'er 8 Steam Separator Removal/Replacement
PPM 2. 14. 1 - Refueling Bridge Operation
PPM 7.0.2 - Shift and Daily Instrument Checks (Mode 5)
These procedures appeared to'e adequate to ensure compliance with the requirements of the Technical Specifications for refueling.
Minor typographical errors were identified by the inspector which licensee representatives agreed to correct.
No violations or deviations were identified.
13.
Licensee Event Re ort (LER Followu 90712, 92700)
The following LERs associated with operating events were reviewed by the inspectors.
Based on the information provided in the reports it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are considered closed.
LER NUMBER LER 88-34-LO LER 88-35-LO DESCRIPTION Pipe Failure Caused by Liquid Nitrogen Missed Required Technical Specification Channel Calibration of IRM Rod Block LER 88-36-LO Failure-to Test Degraded Voltage Relays
LEP. GS-37-LO LER 88-38-LO Plant Shutdown Caused by Containment Supply Purge Valve Air Leak Reactor Building to Suppression Pool Vacuum Breaker Inoperable No violations or deviations were identified.
14.
Review of Periodic and S ecial Re orts (90713 Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9. 1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required to be reported by NRC requirements; test results and/or supporting information were consistent with design predictions and performance specifications; and the reported information was valid.
Within the scope of the above, the following reports were reviewed by the inspectors.
Monthly Operating Reports for February and March 1989.
No violations or deviations were identified.
15.
Exit Meeting 30703 The inspectors met with licensee management representatives periodically during the report period to discuss inspection status, and an exit meet-ing was conducted with the indicated personnel (refer to paragraph 1) on April 14, 1989.
The scope of the inspection and the inspectors'ind-ings, as noted in this report, were discussed 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 inspection..