IR 05000397/1985038
| ML17278A600 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 01/27/1986 |
| From: | Johnson P, Toth A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17278A599 | List: |
| References | |
| 50-397-85-38, NUDOCS 8602130538 | |
| Download: ML17278A600 (28) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report No:
Docket No:
50-397/85-38 50"397 Licensee:
Washington Public Power Supply System P.
O. Box 968 Richland, Wa.
99352
'er 2,
1985 - January 4,
1986'.
)(.
Senior Resident Inspector Da e
S gned
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Date Signed Inspection Conducted:
Dec Inspectors: f ~~ A. D.
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Approved by:. ~
P.
H.
React r hnson, Chief Projects Section
Facility Name: Washington Nuclear Project No.
(WNP-2)
Inspection at:
WNP-2 Site near Richland, Washington Summary:
Ins ection on December
1985 - Janua
1986 (50-397/85-38)
Areas Ins ected:
Routine inspection by the resident inspector of control room operations, surveillance program, maintenance program, licensee event reports, special inspection topics, and licensee action on previous inspection findings.
During this inspection, Inspection Procedures 40700
~ 62700 7 93702
> 907 12 > 92700
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~ 92703 ) 9270 1 ~ 30703
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62703, 61726 and 71710 were covered.
This inspection involved 122 inspection-hours on site by the resident.
inspector, including 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during backshift work activities.
Results:
No violations or deviations were identified.
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DETAILS 1.
Persons Contacted
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Powers, Plant Manager Baker, Assistant Plant Manager Corcoran, Operations Manager Beardsley, Assistant Operations Manager Webring, Acting Technical Manager Harmon, Maintenance Manager Shockley, Health Physics / Chemistry Support Supervisor Little, Planning and Scheduling Supervisor Feldman, Plant equality Assurance Manager McGilton, Nuclear Safety and Assurance Group Manager Peters, Administrative Manager Powell, Licensing Manager Personnel in attendance at exit meeting The inspector also interviewed various control room operators, shift supervisors and shift managers, engineering, quality assurance, and management personnel relative to activities in progress and records.
2.
General The Senior Resident Inspector was on site December 2-7, 8-13, 16-20, 23, 30, 31 and January 2 and 3.
Backshift Inspections were conducted December 6, 7 and 8.
Regional management (J.
Crews) observed INPO team assessment of the licensed and non-licensed operator training programs this month.
3.
Plant Status 4.
0 erations Verifications The plant completed its first year of commercial operation on December 13.
The plant continued operation at about 72% power level through the month, after December 7 restart of the B-loop reactor recirculation system pump showed increasing vibration levels at minimum position of the flow control valve.
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The resident inspector reviewed the control room operator and shift manager log books on. a daily basis for this report period.
Reviews were also made of, the Jumper/Lifted Lead I.og and Nonconformance Report Log to verify that there were no conflicts with Technical Specifications and that the licensee was actively pursuing corrections to conditions listed in. either log.
Events involving unusual conditions of equipment were discussed with the control, room personnel available at the time of the review and evaluated for potential safety significance.
The licensee's adherence to Limiting Conditions for Operation (ICO's), particularly those dealing with
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ESF and ESF electrical alignment, were observed.
The inspector routinely took note of activated annunciators on the control panels and ascertained that the control room licensed personnel on duty at the time were familiar with the reason for each annunciator and,its significance.
The inspector observed access control, control room manning, operability of nuclear instruments, and availability of onsite and offsite electrical power.
The inspector also made regular tours of accessible areas of the facility to assess equipment, conditions, radiological controls, security, safety and adherence to regulatory requirements.
a Valve and electrical breaker alignment, containment isolation valve positions, control fuse installations, diesel generator operability and general condition of equipment, appeared acceptable for the high pressure core spray system (HPCS)
during a system walkdown inspection.
b.
The inspector noted that several of about 50 HFA Century Series relays in the control room were particularly noisy.
The operators appeared to regard this effect as'sual and of no consequence.
Although the devices may simply be responding to electromagnetic action, there also appeared to be the possibility that inte'mal mounting screws may be loosening, similar to coil mounting screw problem for which corrective actions were taken previously by the maintenance department.
Failure of the coils would allow the contacts to move to their deactivated positions, resulting in a system isolation or plant scram, possibly in an unplanned sequence.
The relays in question were MS-RLY-K2D, K3D, K12D and RPS-RLY-K6D, K7D, and K12A.
The inspector discussed these relays with operation and technical management, who stated that they would assure evaluation of the matter.
Followup on this matter will be considered during future inspections.
(85-38-01)
c.
The inspector interviewed an operator, shift supervisor and assistant operations manager regarding activated annunciator 4-1 on panel H13-P826-Pl,
"HPCS Service Water Freeze Protection Trouble".
He also discussed this with one of the quality assurance department surveillance engineers who had recently been involved in reviewing annunciator procedures in the control room'.
The associated annunciator procedure contained a Procedure Deviation Form which recognized; problems with the annunciator itself, and instructed that. the operator verify the 'proper position of certain electrical 'breakers.
It also noted that a
service water pipe temperature recorder had been installed in the rear of the control room.
However, there was no documented instruction, such as theichecklist for operator panel checks each shift,, which,called upon'he operator to check the recorder (however, the.control room supervisor on duty stated that he checks 'it once a day), nor could the operator who was interviewed identify when the electrical breaker check prescribed by the annunciator procedure deviation had last been
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performed (the deviation was dated October 16, 1985, prior to the onset of the very cold weather experienced in November).
The inspector noted that the current temperature reading on the recorder was offscale above 70 F, such that the system was not in jeopardy.
Also, the shift supervisor stated that routine surveillance activities require running of the HPCS service water pump, which avoids and confirms absence of freezing of the line; (running the pump was also one of the annunciator response actions called for by the annunciator procedure deviation).
The above circumstances highlighted that there did not exist a
convenient administrative control for the operators to use to evaluate the need for repeated execution of annunciator procedure action statements, for longstanding activated annunciators.
The operators may rely upon verbal shift turnover information, or prior entries in the operator's logbook (to the extent that such detailed entries may be made).
The assistant operations manager stated that the logbook is the currently appropriate location for such, information, although he recognized that this type of routine detail has not usually been recorded in the past.
This matter will be reviewed during future inspections.
(85-38-02)
The licensee exercised the WNP-2 formal Technical Specification Interpretation procedure in, issuance of TSI-85-004, regarding Technical Specification item F 11.2.8.
This clarified for the operating crews that sampling and analysis of containment atmosphere are not required prior to venting through the standby gas treatment system.
The direction to the staff appeared appropriate.
i The licensee exercised the WNP-2 forrnal Technical Specification Interpretation procedure
'i.n issuance of TSI-85-003, regarding Technical Specification'tem 3.4.9.1.
This clarified for the operating "crews that,"ECCS 'systems may be considered the alternate decay 'h'eat r'emoval metho'd,, with Q.ow through the safety relief valves',and.suction fr'om the suppression pool.
Demonstration of operability would involve review of surveillance results, 'verification of electrical/mechanical alignment, and yerificatioa of available flow path.
This verification approach appeared consistent with NRR guidance relative to this issue at the,IaSalle nuclear plant,,
as documented in a February 15, 1985 staff review memorandum to the Region III,office.
The licensee direction to staff appeared appropriate.
During routine daily examinations of operating equipment the inspector observed that the,.air-operated scram inlet valve stem on one hydraulic control unit was bound by jamming of the shaft position indicating tab against the cable and connector of a solenoid operator of the control rod drive fluid switching valve assembly. It appeared that the binding had occurred upon some prior opening of the scram valve, resulting in failure of
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the valve to fully close after the scram.
The inspector called the shift manager on duty, who disengaged the binding, with resultant full closure of the valve.
The shift manager properly coordinated with the control room operators prior to performing his corrective action, and prepared a nonconformance report to obtain engineering review of the occurrence.
He also arranged prompt inspection of all the hydraulic control units to assure that a similar situation did.not exist on other scram units, and involved of the shift engineer to review the condition.
The immediate corrective actions appeared appropriate.
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During examination of containment isolation valve status, the inspector note'd that the fasteners were not secured on. the cover of containment electrical penetration terminal box TB-R317.
This -box was l'ocated in a limited accessibility area above elevation 522 of the reactor building.
This matter appeared similar to 'the instrument junctiori box cover issue for which a notice of violation was is'sued"with NRC inspection report 85-36, and for which corrective action appeared to have been effective. The,'nspector'dvised the maintenance manager who arranged for prompt correction of the condition.
No other instances of this nature wer'e 'observed by the i.nspector.
At the exit meeting,'he maintenance manager stated that a work request had also:now been issu'ed to inspect all the other electrical penetration junction boxes.
No violations or deviations were identified.
5.
Surveillance Pro ram Im lementation The inspector ascertained that surveillance of safety-related systems, or components was being conducted in accordance with license requirements.
In addition to witnessing and verifying daily control panel instrument checks, the inspector observed portions of several detailed surveillance tests by operators and instrument and control technicians.
a.
During preparations for and conduct of testing of the recirculation system B-pump the inspector noted compliance with the containment inerting requirements of the technical specification, and the jet pump operability daily surveillance procedure.
b.
The inspector observed initiation of several preventive maintenance tasks for radiation monitoring equipment in the plant and the control room, with appropriate notifications of the control room supervision and reactor operators.
No violations or deviations were identified.
6.
Monthl Maintenance Observation
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f Portions of selected safety-related systems maintenance activities were observed.
By direct observation and review of records the inspector determined whether these activities were consistent with I,COs; that the'roper administrative controls and tag-out procedures were followed; that equipment was properly tested before return to service.
The inspector also reviewed the outstanding job orders to determine if the licensee was giving priority to safety related maintenance and verify that backlogs which might affect system performance were not developing.
a.
For improved control of chemicals within the plant, the licensee had posted prominent. posters in principal plant access points, with four color codes identified and defined.
These codes identify. the areas of the plant where different types of chemicals are allowed or prohibited.
Commensurate color codes have been affixed throughout the plant at stairwells, doorways and access corridors.
Plant staff specific training in this area remained to be conducted.
b.
The inspector examined nonconformance report (NCR) No.
21952 associated with an old Bechtel quality control hold tag affixed to a weldolet of the low pressure core spray system.
This NCR addressed five weldolets on the IPCS system and was somewhat unclear as to the basis for the final disposition.
The WPPSS welding engineer inspected the welds and found them acceptable, with exception of one which appeared to have excessive overgrinding gouges.
He referred this one to the stress engineer for followup.
The discrepancy did not appear to be significant; however, the resolution of this matter will be reviewed during a future inspection.
(85-38-03)
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The inspector observed that cables from the barometric pressure compensators had been disconnected from the spray pond water level transmitters in the pump houses.
These were for the level indicators in the control room; the transmitters for the remote shutdown panel (specifically required to be operable per Technical Specifications)
were properly connected.
The loose cables were labeled with an in-progress work request, which had been initiated in early 1985, to investigate instrument drift problems.
The lifted leads were not entered into the lifted lead log in the control room; however, the control room staff was fully aware that the level indicators were not currently accurate, and had implemented a manual verification of satisfactory spray pond level as part of the documented instrument checks each shift.
The gauges were also marked as questionable on the control room panels.
The jumper and lifted lead procedure provided some exceptions to the required implementation of the control room log, and the Plant Hanager stated that the details of such exceptions would be re-examined relative to this particular situation.
Also, at the exit, meeting the plant manager committed to a review of other in-progress maintenance work requests to ascertain that a
similar situation of compromised equipment status does not exist without identification in control room records.
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licensee's actions will be examined during a future inspection.
(85-38-04)
No violations or deviations were identified.
7.
En ineered Safet Feature Verification The inspector verified the operability of the Residual Heat Removal System (Low Pressure Coolant Injection System),
I.oop C, by performing a walkdown of the accessible portions of the mechanical, electrical and instrumentation portions of the system.
The inspector confirmed that the licensee's system lineup procedures matched plant drawings and the as-built, configuration with regard to critical performance parameters.
The inspection included examination of logic and relaying hardware status compared to applicable drawings, and verification that valves were in the proper position, power was indicated by motor control center breaker positions and supervisory annunciator status, and locks were in place as appropriate.
Critical instrument calibration records were examined regarding trends, and as were records of breaker cabinet preventive maintenance cleaning.
Clearance order and jumper and lifted lead logs were reviewed for items which may affect system operability.
Several minor housekeeping items were identified during inspection of areas of low traffic, and these were identified to plant management for inclusion in the general maintenance activities.
No violations or deviations were identified.
8.
Licensee Event Re orts A regional inspector performed an in-office review of the following Licensee Event Reports (LERs) relative to timeliness, adequacy of description, generic implications, planned corrective actions, and adequacy of coding.
The resident inspector reviewed the following reports and supporting information on site to verify that licensee management had reviewed the events, corrective action had be'en taken, no unreviewed safety questions were involved, and violations of regulations or Technical Specification conditions had been identified.
a.
LER-85-059-00 (Closed) Reactor Scram Due, to Instrument Power Inverter Failure - The inspector reviewed the operations staff activities following th'e reactor scr'am, as discussed in NRC inspection report 85-37 (Para. 8.a.).
He also subsequently interviewed shift personnel and attended the Plant Operations Committee,(POC)
meeting at which this event was discussed.
The POC identified -that care 'in preplanning troubleshooting, especially of equipment'hich is on-line, must be increased.
As a result, action was'taken to,generate a special review of this item in. a monthly operating bulletin which will be distributed to affected plant. staff personnel.'
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LER-85-061-00 (Closed) Reactor Scram Due To High Upscale IRM-The inspector reviewed the operations staff activities following th'e reactor scram, as discussed in NRC inspection report 85-37 (PARA. 8.b.).
He also attended the POC meeting at which this matter was discussed.
The nuclear engineer on duty at the time of the scram gave a presentation of the details of the event and the root cause.
It was concluded that the operator might have avoided the short, reactor period if more thorough information had been provided relative to expected reactivity behavior for the specific control rod configuration and age.
Neither the review nor the LER identified that the operator apparently was expected to be able to respond in time to prevent a scram if the reactor period was as short as
seconds; i.e. the startup procedure PPM-3.1.2 step
instructed the operator to "approach the power range on a stable period of about 60 - 100 seconds.
If a period of less than 25 seconds is observed due to unplanned reactivity increase, insert the rods until the reactor is subcritical".
The operator apparently had been attempting to maintain a
reactor period at about 60 seconds; i.e. the first of the two-step control rod pull had resulted in a period slightly less than 60 seconds, and the second step pull was initiated as soon as the period increased to about 67 seconds.
As a result of the second step pull, the reactor period went to 32 seconds, with a reactor scram 20 seconds thereafter.
The IER and the POC review did not address the inability of the operator to respond to reactor period meters and reverse the rod withdrawal step within the 20 seconds.
However, the Plant Manager stated that he was aware of the discrepancy and has requested a
further review of the circumstances toward preventing recurrence.
The LER describes plans to provide operators with additional information to better anticipate effects of varying reactivity conditions of the reactor core, which appears to address one element to prevent recurrence of this type event.
The LER attributed the event to personnel error arising from insufficient information available to the operator, with no discussion relative to the operator's ability to respond to a 32 second period condition.
The Reactor Trip and Recovery procedure.
(PPM-1.3.5) specified a
detailed review and root cause analysis, to be completed within 3-days unless extended by the Technical Manager (which, apparently, it was).
This report,was not issued until December 18, and the principal reviewers were. the shift engineer and shift manager who had been on duty at the time of the event.
Plant management recognized the desirability of increasing the independence of the review committee for such events, and has initiated a procedure change, to provide for participation of a representative of the Nuclear Safety Assurance Group (NSAG).
The licensee NSAG has also initiated a more detailed study of this even I l
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The LER is considered closed.
However, the licensee's, followup actions regarding additional procedures and results of the NSAG review will be considered during a future inspection.
(85-38-05)
No violations or deviations were identified.
9.
Licensee Actions On Previous NRC Xns ection Findin s The inspector reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
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(Closed) Violation (84-09-02) - Failure To Control Work On Pire Suppression System.
'Pipe clamps were not replaced after work on piping of the deluge spray system.
The inspector verified the actions described in the Supply System letter to NRC dated September 6,
1984.
Xn addition, the valve station piping had been reworked with installation of new valves and actuators.
All pipe supports appeared to be secured.
The inspector noted that some bolts holding the act'uators to their mountings did not appear to fully engage the bolt. holes.
The licensee promptly performed an engineering evaluation and elected to replace the bolts with longer ones.
The inspector ascertained that this had been accomplished.
This item is closed.
b.
(Closed) Violations (84-13-03, 85-09-04, 85-09-05, and 85-09-07) - Pai3,ure To Notify NRC Operations Center of Events Within lOCFR50.72 Time Requirements The licensee.'s July 26, 1984'eply to, item 84-13-04 stated that, operating crews had developed a working knowledge of the requirements of 10CFR50.72 and'no further corrective action was required.
The subsequent findings of inspec'tion report 85-09, and the related February 28, 1985 enforcement conference, indicated that further action was necessary on the part of licensee management.
The licensee's reply'of March 19, 1985 advised of improvements to the scram recovery procedure 1.3.9 and directions 'to shift engineers to become involved in the notification decision early'in the progress of any event.
The inspector 'interviewed several Shift Engineers and Shift Managers regarding heportability, examined the revised procedure 1.3.9, and has observed the use of the procedure in reactor scrams which have occurred since February 1985.
The notification aspects of an event are highlighted in the procedure and the personnel appeared quite sensitive to the requirements.
Since February, the Shift Managers have reported several events, each on a timely basis, including notification of the resident inspector, and 9.n some cases have provided courtesy notification of items which were not clearly required to be reported under 10CFR50.72.
(Such courtesy notifications
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have been lxseful in supporting NRC inspection activities).
The licensee's corrective actions were's stated in the letters to NRC, and appeared reasonable and successful in maintaining compliance with the lOCFR50.72 requirements since February.
The above noted violation issues are considered closed.
(Closed) Violation (84-18-05) - Failure To Implement Timely Corrective Action For Inoperable Inhibit Function of Automatic Depressurization System".
Interim or permanent corrective actions were not, implemented for the pump-running conditional relay, which was misled by high pressure conditions in the low pressure coolant injection, system.
The WPPSS letter to NRC dated August 7, 1984 described a
technical argument that the inhibit design feature, and associated 'technical specification, were not necessary.
The discussio'n did not address single failure criteria of High Pressure Core Spray system inoperability, nor adequacy of reliance on 'non-quality control rod drive and reactor core isolation cooling systems.
It, proposed that the automatic depressurization system was not inoperable, even though the pump-running inhibit function would not have precluded reactor, depressurization under the 'unlikely condition of no ECCS pumps operable.
Since the identification of this issue in June 1984, the resident inspectors have observed control room operations daily, with routine consideration of annunciators in the alarm condition, and observation of operator response.
The previously identified condition has not been subsequently observed, and design modification and operator actions have apparently prevented its recurrence.
This item is closed.
(Closed) Violation (85-30-01)- Failure to implement administrative procedures for deviations from specifics of plant operating procedures.
Reactor operators adjusted suppression pool level without implementing sampling and pump operations aspects of the applicable abnormal condition procedure.
The inspector reviewed the actions described in the MPPSS letter to NRC dated October 18, 1985.
The Operations Manager placed appropriate instructions in the night order log to emphasize the requirement to comply with the existing procedure, pending completion of system modifications and revision of the procedure.
The inspector observed operations and/or operator log entries since August 1985 and noted special emphasis to demonstrate routine compliance with the new directions.
The WPPSS letter specifically addressed an apparently valid point; i.e. it'was not appropriate for the operator to implement the emergency procedure under conditions of slightly abnormal operation, (however, the annunciator procedure did
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specifically direct'the operator to certain paragraphs of that procedure).
Since identification.of this m'atter by NRC, the licensee has issued an approved procedure deviation form, filed with the annunciator procedure.
"This clarified the condition under which the emergency procedure would be entered (which requires sampling of suppression pool water)
and directed utilization of,the normal mode system operating procedure (PPM-2.4.2)"for adjusting suppression pool level under slightly abnormal conditions.
This item is closed.
t (Open) Followup'tem,(84-15-01)'
Finding "f" - Some operational occurrences were not being routinely recorded in the control'room logs.
Paragraph 10.c below describes examples of items which indicate that licensee management actions for this matter have not been fully successful in obtaining cooperation of the operations staff to provide meaningful detail in their logs.
This has increased reliance on other aspects of management's personal involvement in the day to day operational details.
This area will continue to be subject of special inspection efforts.
10.
S ecial Ins ection To ics a
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Nitro en Inertin S stem Desi n and 0 eration The inspector reviewed licensee actions relating to a General Electric Company Service Information Letter (SIL-402) arising from veht header cracks experienced at, the Hatch Unit 2 plant.
These actions also relate to IE Bulletin 84-01 and information notice 84-17.
The licensee Nuclear Safety Assurance Group and the technical staff engineers had evaluated the WNP-2 plant inerting system design relative to potential failure modes and effects on containment structures from inadvertant liquid nitrogen flow.
This effort included contact with the Hatch plant staff and review of the Hatch detailed nitrogen system design and discussion of their operating procedures prior to the event.
The WNP-2 nitrogen system design is the same as that at the Hatch plant.
The nitrogen gasification equipment is located outside, exposed to the elements, and lines to the containment tie-in points are long and uninsulated.
The 6-inch diameter nitrogen inerting line connects to the containment structures via a connection to a 30-inch main purge line.
This purge line could be susceptible to a brittle fracture similar to Hatch 2.
However, the connection point is outside the second containment isolation valve and a failure in liquid nitrogen gasification equipment and temperature monitoring controls should not result in an unisolable containment failure from direct impact on the containment structure.
To further insure against such failures, the MNP-2 system operating procedures have been modified to:
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(1) Alert operators that "Loss of temperature control in nitrogen inerting or makeup systems provides a potential for brittle fracture at containment boundaries; maintain temperatures above 0 F where specified by this procedure."
(2) Require operators
"awhile the containment inerting header is in service (Steps 6 through 18 of the procedure 2.3.1),
insure the temperature at CN-TI-2 on the nitrogen skid is maintained above 0 F.
Alternatively, verify the temperature at CN-TI-12 RB 501's maintained above 0 F."
An additional 1" nitrogen makeup line is connected to the vent header between the containment structure and the first isolation valve.
This is a low flow line, for which the ambient temperature evaporators are expected to assure gasification prior to flow reaching the tie-in point.
These evaporators are also expected to maintain acceptable temperature control for flow to the containment instrument air system, containment vacuum breakers, and TIP system purging.
No violations or deviations were identified.
Vibration Testin of the Reactor Recirculation S stem Pum The inspector observed vibration testing of the recirculation system pump RRC-P-1B on December 6-8, 1985.
The licensee provided significant technical and management, support of the testing, including night shift periods necessitated by delays due to instrument power supply failures.
The technical department middle managers acted as test directors, with Engineering and Technical department supervisors and staff observing the tests and assisting in evaluation of test data.
The plant manager and assistant plant manager were present in the control room during testing and were involved in key decisions to continue or cease testing activities.
General Electric Company vibration analysis consultants supplied vibration monitoring and recording instrumentation and performed data gathering and analysis services.
The arrival of the consultants was delayed due to the weather and the licensee appropriately deferred testing until arrival of these personnel.
The two RRC pumps were started, on 15 HZ low speed operation and then shifted to 60 Hz high speed operation with the flow control valve at its minimum 'open'osition, in accordance with approved normal plant procedures.
At minimum flow valve position the vibration amplitudes reached 11.5 and 12 '
mils in the x and y directions, respectively, at which time the test was terminated in accordance with the, shutdown criteria in the approved test procedure.
The pumps were resta'rted after engineering meetings and review and approval by the plant manager and assistant. plant manager,
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in order to confirm readings and to obtain phase relationship information necessary to permit, balancing of the pump shaft.
At 60 Hz high speed operation and minimum open position of the flow valve, the vibration amplitudes were 12 and 12 mills in the x and y directions, respectively.
The phase of the vibration was noted to have changed position by 45 degrees between the first test and the second.
Within five minutes the flow control valve was opened to its 10% position, at which time vibration amplitudes changed to l1.0 mils and 13 mils in the x and y directions, respectively.
The pump was shut down and the test terminated.
The licensee staff decided that the shift in phase angle indicated that pump shaft balancing would not be successful, and plans to perform such work were abandoned.
At this time the licensee plans to continue operation with only the RRC A pump in service, which results in a power limitation of about 72/.
This operating mode is anticipated to continue until the spring refueling outage, when the B pump will be disassembled and inspected.
c.
'Control Room Lo Details The inspector examined the Shift Manager's log and the reactor operator log books relative to adequacy of details of operational events.
The Shift Manager's log is copied and considered by the plant department managers in a meeting each morning.
Additionally, the Assistant Operations Manager or the Operations Manager visits the control room and interviews the Shift Manager regarding operational experiences daily prior to the morning meeting.
The inspector considered two items which had occurred and had been discussed at the morning meetings:
(1)
A pressure transmitter controlling the RHR/LPCI "C" loop minimum flow line control valve was found with its equalizing valve open such that the control valve would not automatically close after flow injection to the reactor commenced.
The logs did not discuss the pot'ential impact of this situation nor did they document that the operations staff conducted a flow test, to verify operability of this ECCS system, i.e.
measured flow with the valve full open to demonstrate that diversion of flow through the minimum flow line would not reduce reactor injection flow capability below that required by Technical Specifications.
(2)
A system transient was,'introduced when a technician conducting a surveillance test loosened the terminal lug on an active logic system to install an electrical'umper.
The jumper was issued in accordance with'he jumper control procedure, but was a spade-lug jumper as opposed to an alternative
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alligator clip type termination.
Although a nonconformance report was issued, which should have resulted in engineering evaluation of the event, the control room logs did not discuss the nature of the error.
As a result, the matter was not discussed in the morning department managers'eeting, nor was the instrument supervisor advised of the matter until the inspector interviewed him after the morning meeting.
The nonconformance report was mentioned at the morning meeting in only the most general terms.
The NRC inspector will continue to monitor the adequacy of detail of control room logs.
Although licensee management has issued improved guidance regarding the content of control room logs, the examples encountered above appear to demonstrate that implementation of such guidance has not been consistent.
This is a continuation of the log adequacy subject identified during the June 1984 NRC team inspection (84-15-01).
No violations or deviations were identified.
11.
Mana ement Meetin The inspector met. with the project manager approximately weekly during this period, to discuss inspection finding status.
On January 3, 1986, the inspector met with the Plant Manager and members of his staff to discuss the inspection findings during this period.
The licensee noted that a position of Compliance Engineer has been established to prove'de'a principal focal point for discussion of inspection findings during the, report period.
This tended to assure the licensee opportunity to'ffect prompt corrective actions, where necessary, an'd to assure that management wasisufficiently cognizant of issues prior to the e'xjt meeting to allow determination of meaningful commitments, or statements of position.
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During the current report 'period;
-a combination of holidays and illness delayed e'stablishment 'of'his function prior to the exit meeting.
As a result, apt hll i'ssues were clarified at the exit meeting.
Additional'nfor'mati'on'as presented by the licensee on January 9, when, the inspector returned to, the sit V
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