IR 05000528/1988029
| ML17304A694 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 10/20/1988 |
| From: | Ball J, Coe D, Fiorelli G, Polich T, Richards S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17304A693 | List: |
| References | |
| 50-528-88-29, 50-529-88-28, 50-530-88-27, NUDOCS 8811040314 | |
| Download: ML17304A694 (30) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
Docket Nos:
License Nos:
Licensee:
50-528/88-29, 50-529/88-28 and 50-530/88-27.
50"528, 50-529, 50-530 NPF"41, NPF-51, NPF-74 Arizona Nuclear Power Project P.
0.
Box 52034 Phoenix, AZ. 85072-2034 Facility Name:
Palo Verde Nuclear Generating Station Units 1, 2 8 3.
io ->0-%
Date Signed lo-Qo-SS Date Signed Inspector:
Inspector:
Inspection Conducted:
August 14 through September '17, 1988 T. Polich, Senior Resident Inspector J. Ball, Resident Inspector Inspector:
Approved By:
G. Fiorelli, Resident Inspector D.
Coe, Resident Inspector S.
Richards, Chief, Engineering Section Date Signed
<o- >O-SS Date Signed Lo-20-SS Date Signed Summary:
Ins ection on Au ust 14 throu h Se tember
1988 Re ort Numbers 50-528/88-29 50-529/88-28 and 50-530/88-27.
Areas Ins ected:
Routine, onsite, regular and backshift inspection by the four resident inspectors.
Areas inspected included: previously identified items; review of plant activities; areas observed on plant tours:
operating logs and records, monitoring instrumentation, shift manning, equipment lineups, equipment tagging, general plant equipment conditions, fire protection, plant chemistry, security, plant housekeeping, radiation protection controls; engineered safety feature system walkdowns; surveillance testing; plant maintenance; reactor trip following main turbine trip on low stator cooling flow - unit 1; reactor trip following generator synchronization
- unit 1; letdown containment isolation valve post-maintenance retest - unit 2; reactor power cutback - unit 2; fai lure to perform quality control holdpoint - unit 2; signoffs not made as maintenance was performed - unit 2; inaccuracies in calculation of estimated critical conditions - unit 3; temporary instruction TI-15-93 - verification of quality assurance request regarding diesel generator fuel oil; followup licensee event report - units 1, 2 and 3; and review of periodic and special reports units 1, 2 and 3.
3-'l $ 040= 14 3-'i.A20 PDR ADOCK 050C>05."3 CI PDC
During this inspection the following Inspection Procedures were covered:
30703, 25593, 61726, 62703, 71707, 71710, 92701, 92703, 93702.
Results:
General Conclusions and S ecific Findin s
The training provided to the guality Assurance (gA) Director since his appointment to the position in October, 1987 was reviewed.
Since that time, he has received only two days of training.
This training was considered by the inspector to be minimal considering the involved individual's past experience in gA.
.2.
The licensee's review of a reactor trip at Unit 1 was considered by the inspectors.
The inspectors were of the opinion that the review did not adequately address personnel performance problems associated with the trip.
3.
A maintenance worker at Unit,3 inappropriately entered a locked high radiation area by defeating the lock using a screwdriver.
This event will be followed up on by a regional health physics inspector.
4.
Several events were reviewed by the inspectors which all appeared to have been avoidable.
A Unit 1 trip was initiated by a faulty flow switch in the stator cooling water system.
The licensee recognized a problem with the switch two days prior to the event, however troubleshooting efforts did not permanently fix the problem or determine the cause of the switch acting erratically.
A reactor power cutback occurred at Unit 2 because maintenance instructions for work on a feedwater valve did not adequately consider the effect of the work on an associated main feedwater pump (MFP).
The performance of the job resulted in the inadvertent trip of the MFP and the subsequent reactor power cutback.
At Unit 2, an Emergency Diesel Generator (EDG) was rendered inoperable by the failure of a drain plug on an inner cooler.
A similar failure had previously occurred at Unit 3, however the licensee's corrective action was delayed at Unit 2 and did not prevent a recurrence.
Si nificant Safet Matters:
None Summar of Violations:
None Summar of Deviations:
None 0 en Items Summar
Six items closed, three items left open, and two new items opene DETAILS Persons Contacted:
The below listed technical and supervisory personnel were among those contacted:
Arizona Nuclear Power Pro ect ANPP R.
AJ P.
"R.
C L.
)hJ
- H W.
- J W.
R.
J.
W.
8'D
'J.
R.
"A.
S K.
R.
W.
Adney, Manager, Plant Standards and-Control Allen, Plant Manager, Unit 1 Brandjes, Manager, Central Maintenance Buckingham, Operations Mangager, Unit 2 Butler, Director, Standards and Technical Support Churchman, Manager, Work Control Unit 3 Clyde, Supervisor, Shift Technical Advisors Dennis, Manager, Work Control Unit 1 Beyer, Supervisor, Work Control Unit 3 Doyle, Manager, Radiation Protection, Unit 2 Driscoll, Assistant Vice President, Nuclear Production Fernow, Manager, Training Gouge, Operations Manager, Unit 3 Haynes, Vice President, Nuclear Production Ide, Plant Manager, Unit 2 Karner, Exec.
Vice President, ANPP Administration Kirby, Director, Site Services Logan, Supervisor, Central Radiation Protection McCabe, Maintenance Manager, Unit 1 Minnicks, Maintenance Manager, Unit 3 Moyers, Supervisor, Plant Standards and Control Oberdorf, Manager, Radiation Protection, Unit 1 Papworth, Director, guality Assurance guinn, Director, Nuclear Safety 8 Licensing Riley; Jr.
Lead Mechanical Engineer Scott, Manager, Work Control Unit 2 Shriver, Manager, Compliance Si lls, Supervisor, Radiation Protection Standards Simko, Supervisor, Mechanical and Civil Engineering Sowers, Manager, Engineering Evaluations H.
AJ J.
B.
G.
"P. Trimble, Senior Engineer R. Younger, Operations Manager, Unit 1
"0. Zeringue, Plant Manager, Unit 3 The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
- Attended the Exit Meeting on September 22, 198 Previousl Identified Items - Units
2 and
92702 a.
Cl os'ed Fol 1 owu Item 528/87-17-01:
"Train Outa e Procedures".
The licensee has modified procedure 300P-9WP02,
"Work Planning," to include instructions which are to be implemented when work involves online outages of Engineered Safety Feature (ESF) trains.
This item is closed for the three units.
b.
Closed Enforcement Item 528/88-07-01:
"Licensee Event Re ort LER 87-25 Modifications to Steam Turbine Driven Auxiliar Feedwater Pum Isolation Valves Render Pum
.Ino erable".
The licensee's response to the Notice of Violation specified eighteen corrective actions which would be taken to avoid further violations.
These actions are being followed under open items 528/88-07-02, 03, and 04.
This item is closed based on the licensee's action to restore auxiliary feedwater pump operability.
C.
0 en Enforcement Item 528/88-07-02
- "Review of Modification Inade uate'
The following licensee commitments were verified by the inspector (the numbers are related to the order in which commitments appeared on the licensee's reply to the Notice of Violation):
(1)
Limitorque switch settings for safety related motor operated valves have been included in the design basis by placement in a controlled plant drawing.
In addition, the drawing was annotated to indicate the proper relationship between the auxiliary feed pump ramp up switch (Rotor No. 3) and valve open limit switch (Rotor No. 1) on the valves involved with the auxiliary feed pump operability events.
This action is complete.
'(2)
The engineering evaluation is in progress to determine if any additional parameters need to be added to the design basis.
Scheduled completion is December 1988.
This item will be followed by the routine inspection program.
Review of this action is complete.
-(3)
The Engineering Evaluation Request (EER) procedure has been modified to require the Evaluator and the Evaluator's Supervisor to be specifically responsible for obtaining a
cross-discipline review when necessary.
In addition, the use of an EER for design changes has been restricted to as-found non-conforming conditions, and requires a checklist and review process equivalent to a site-modification, and cannot alter any as-built drawings or inservice procedures.
This action is complete.
(4)
Training on the revised EER procedure, site modification procedure, and the design change process was given to the System and Design Engineers.
This action is complet (5)
A gA audit was conducted to determine if other design basis changes had been made using the EER process.
A total of 126 EER's were sampled, representing over 10K of the applicable EER's since mid 1986.
The results of this audit have been responded to by the Engineering Evaluation Department.
An independent review of the findings and responses by the licensee's Engineering Department will be required prior to closure of this item.
(6)
Procedure 73PR-9ZZ04,
"Valve Motor Operator Monitoring and Test
. Program,"
was revised to require any motor operated valve (MOV)
limit switch setting changes to be made within the specifications of the design drawing, or else require use of the design change procedure.
In addition, the EER procedure was modified to specifically allow MOV limit switches to be adjusted within the range specified in the design drawing, but only with the checklist and review process equivalent to that used for a site-modification.
This action is complete.
d.
0 en Enforcement Item 528/88-07-03
- "Inade uate Retest".
The licensee implemented a new Retest procedure on August 22, 1988, as part of an overall major modification to the work control procedures.
The inspector noted several work orders issued after the implementation date which did not include the newly required Retest Evaluation Form, which certifies the quality of the specified retest.
One of the work orders was associated with a containment isolation valve.
Although the inspector did not identify any improper retests, this item will remain open pending further review of this and other provisions of the new retest procedure requirements.
0 en Followu Item 528/87-44-01:
"Trainin For The Cor orate ualit Assurance A
Director.
Chapter 17.2 of the FSAR describes the licensee's gA program for the operations phase of Units 1, 2 and 3.
Significant recent changes to the gA program included the elimination. of the position of Assistant gA Director and the replacement of the gA Director.
These organizational changes were submitted by the licensee to the NRC office of Nuclear Reactor Regulation (NRR) on August 10, 1987.
NRR issued an SER input, dated October 2, 1987, concerning acceptance of these changes.
The licensee's justification for elimination of the Assistant gA Director postion was found acceptable.
NRR also approved the licensee's replacement for the position of gA Director with the stipulation that training would be provided to the new gA Director to compensate for the Director's lack of one year experience within the gA organization.
In December 1987, the inspector discussed these changes with the new gA director, who indicated that he had not received any gA training; however, training would be provided within the next few months.
In April, 1988, the gA Director received two days of training from the Management Analysis Compan The licensee has recently contracted with a consultant to provide additional training to the gA Director on a continuing basis.
The same consultant will also be providing'n assessment of the current gA organization.
f.
Closed Followu Item 528/88-12-01:
"Labelin on Subcooled Mar in Monitor".
An inspection of the Unit 3 Reactor Cooling System (RCS) monitor confirmed that the Unit 3 RCS subcooling channel SHA-TI-3 indicator is labeled "subcooled" and "superheat".
The inspector also reviewed an FSAR revision submittal which will change the indicated range of the core exit temperature subcooled monitor from (+)700 degrees F-(-)2100 degrees F to (+)200 degrees F - (-)800 degrees F, to be consistent with the control room indicator.
This item is closed for the three units.
g.
Closed Followu Item 528/88-12-02
- "Labelin of Pressurizer Heater Current".
h.
The inspector noted that tag numbers identifying the dedicated Class 1E pressurizer heaters are sufficiently close to the ammeters on control board 804, that they would serve to identify the respective heater currents.
This item is closed for the three units.
Closed Enforcement Item 528/88-02-01:
"Ino erable Hi h
Pressure Safet In ection Pum s Durin Mode 4".
The inspector verified that the following Unit 1 procedural changes had been made.
410P-1ZZ01 Specifies restoration of the high pressure safety injection (HPSI)
pump prior to Mode 4 entry.
40AC-9ZZ18 Identifies controls related to the use of the Technical Specification component condition record.
ANPP-EX0106 Identifies controls associated with the use of procedure feedback forms.
Specifies verification of status of safety 410P-1ZZ01~
equipment monitored by the SESS.
The procedures for Units 2 and 3 were similarly modified.
This item is closed.
i.
Closed Unresolved Item 530/87-36-01:
"Verification of H dro en Anal zer Ran e
Ca abi'lit To Neet FSAR Re uirements.
This item relates to a concern regarding testing of the hydrogen analyzers and their capability to meet the detection range of 0 to 10 percent hydrogen as stated in the FSAR.
Routine surveillance and
calibration of the analyzers was found to be performed over a range of 0 to 4 percent hydrogen.
In discussions with the system engineer at the time of theprevious inspection, it was not clear if the system's true capabilities had ever been established.
The licensee committed to perform a test to determine if the analyzers were indeed able to detect up to 10 percent hydrogen as stated in the FSAR.
The results of the licensee's test did show the analyzers were able to respond up to 10 percent hydrogen although without the precision'chieved within the lower range of the detector.
The licensee has submitted changes to the FSAR to more clearly delineate the analyzers capabilities with justification that under any analyzed accident, hydrogen concentration should never exceed
percent and thus precise measurements above that point are not required.
Based on the licensee's test results, and justification for changes to the FSAR and the submittal of those changes, this item is closed.
3.
Review of Plant Activities 71707 a ~
Unit 1 Unit 1 began the report period in Mode 4 and was brought critical on August 18, 1988, and was synchronized to the grid on August 20.
On August 21, 1988, 'a main turbine trip resulted from the failure of a flow switch in the stator cooling flow trip circuit.
The reactor, subsequently tripped on high pressurizer pressure from 75K power as the result of the premature closure of two steam bypass control valves (See Section 7).
On August 27, 1988, a reactor trip occurred from approximately 12K power following synchronization of the main turbine to the grid.
The trip was caused by a Low Steam Generator No.
1 level condition following a trip of the "B" main feedwater pump.
(See Section 8).
b.
Unit 2 Unit 2 operated essentially at 100K power from the start of the inspection period until August 30, 1988, when power was reduced to 40K for repair of a suspected condenser tube leak.
No tube leak was found, however a valve was found open in the condensate cross tie line between Units 2 and 3.
The open valve in the line, which was under vacuum, allowed chemically contaminated water which had accumulated in the valve pits to enter the condensate system providing the indications of an apparent condenser tube leak.
The unit was returned to lOOX power on September 1, 1988, and remained at essentially full power until September 6, 1988, when a reactor cutback occurred while performing maintenance on an air line oiler associated with the "A" main feedwater pump minimum flow recirculation valve (See Section 10).
The plant returned to full power later that day and remained at essentially full power until the end of the report perio Unit 3 On August 18, Unit 3 returned to service following repairs to the
"B" Phase Main Transformer which was struck by lightening on July 31 and the completion of other shor t notice outage work.
On August 25 while operating at 100K power, the unit experienced a reactor power cutback to 50K power when the "B" Main Feedwater Pump tripped during the performance of a routine weekly overspeed trip test of the pump turbine.
The cause of the trip was found to be the failure of the lockout solenoid valve which is energized during the test to prevent an actual trip of the pump.
The licensee replaced the failed valve and successfully tested the pump.
The unit returned to lOOX power on August 26 and remained there until the end of the report period.
Plant Tours The following plant areas at Units 1, 2 and 3.were toured by the inspector during the course of the inspection:
o Auxiliary Building o
Containment Building o
Control Complex Building o
Diesel Generator Building o
,
Radwaste Building o
Turbine Building o
Yard Area and Perimeter The following areas were observed during the tours:
1.
0 eratin Lo s and Records Records were reviewed against Technical Specification and administrative control procedure requirements.
2.
Monitorin Instrumentation Process instruments were observed
- for correlation between channels and for conformance with Technical Specification requirements.
conformance with 10 CFR 50.54.(k), Technical Specifications, and administrative procedures.
4.
E ui ment Lineu s
Valve 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 the conduct of partial system lineups.
5.
E 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 in the condition specified.
6.
General Plant E ui ment Conditions Plant equipment was observed for indications of system leakage, improper
lubrication, or other conditions that would prevent the systems from fulfillingtheir functional requirements.
I 7.
Fire Protection Fire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures.
conformance with Technical Specifications and administrative control procedures.
9.
~gecurit Activities observed for conformance with regulatory requirements, implementation of the site security plan, and administrative procedures included vehicle and personnel access, and protected and vital area integrity.
10.
Plant Housekee in Plant conditions and material/equipment storage were observed to determine the general state of cleanliness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
ll.
Radiation Protection Controls Areas observed included control point operation, records of licensee's surveys within the radiological controlled areas, posting of radiation and high radiation areas, compliance with Radiation Exposure Permits, personnel monitoring devices being properly worn, and personnel frisking practices.
e.
Radiation Protection Event On September 8, 1988, an electrician at Unit 3 used a screwdriver to defeat a locked gate at the access to a locked high radiation area.
Additionally, the work order he was following specified a Radiation Entry Permit (REP) that did not allow access to high radiation areas.
This is an apparent violation of 10 CFR 20.203 (c)
2 (iii).
Other problems were also noted, however this item will be followed by Regional Health Physics inspectors in inspection report 50"530/88-31
'o violations of NRC requirements or deviations were identified.
4.
En ineered Safet Feature S stem Walkdowns - Units 1 2 and
71710 Selected engineered safety feature systems (and systems important to safety)
were walked down by the inspector to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical cabinets, and cables were inspected to determine that they were operable, and in a condition to perform their required function Unit 1 Accessible portions of the following systems were walked down during this inspection period.
~Sstem o Diesel Generators Trains "A" and "B" o Emergency Spray Ponds Unit 2 Accessible portions of the following systems were walked down during this inspection period.
~Sstem o Diesel Generators Trains "A" and "8" o Emergency Spray Ponds Unit 3 Accessible portions of the following systems were walked down during this inspection period.
~Sstem o Diesel Generators Trains "A" and "B" o Emergency Spray Ponds No violations of NRC requirements or deviations were identified.
5.
Surveillance Testin
- Units 1 2 and
61726 Surveillance tests required to be performed by the Technical Specifications (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 performance 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.
Portions of the following surveillances were observed by the inspector during this inspection period:
Unit 1 o 41ST-lDG02 Diesel Generator
"B" Test
Unit 3 o 73ST-9HF01 Fuel Building AFU Air Flow Capacity and Pressurization Test o 41ST-3DG02 Diesel Generator
"A" Test No violations of NRC requirements or deviations were identified.
6.
Plant Maintenance - Units 1 2 and
62703 a 0 During the inspection period, the inspector observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements, compliance 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 inspector verified that reportability for these activities was correct.
b.
The inspector witnessed portions of the following maintenance activities:
Unit 1 o Repair of "D" Circulating Water Pump Unit 2 o Repair of "A" Diesel Generator Inner Cooler Unit 3 Descri tion o "B" Main Feedwater Pump Troubleshooting Unit 2 experienced a failure of a Diesel Generator Inner Cooler drain plug during this inspection period.
This is the second occurrence of this type.
The first failure was identified at Unit 3.
Information regarding the first fai lure was exchanged between units and work orders were'written to inspect and tighten the drain plugs on Units 1 and 2.
However, only Unit 1 followed through and corrected the problem.
Unit 2 prioritized the work to be performed during the next diesel generator outage.
The inspector emphasized with licensee management the need to promptly followup equipment problems that can affect other trains or units.
No violations of NRC requirements or deviations were identifie Reactor Tri Fol lowin 'ain Turbine Tri on Low Stator Cool in Flow
- Unit l. (93702 On August 21, 1988, Unit 1 was operating at approximately 75K rated thermal power when the main turbine tripped on a low stator cooling water flow signal.
Approximately 15 seconds later the reactor tripped on high pressurizer pressure.
The inspector reviewed the licensee's Post Trip Review Report, (PTRR) 1-88-005, to assess the thoroughness of the licensee's review and corrective actions taken.
In general, the inspector found that the licensee adequately addressed all areas of concerns.
The inspector, however, was compelled to discuss further with the licensee two particular areas of concern.
The first area of concern was related to the initiation of the main
. turbine trip on low stator cooling water flow when no such condition existed.
The initiation signal was eventually determined to have resulted from the failure of a differential pressure switch.
Two days prior -to this event, a similar turbine trip occurred prior to exciting the main generator.
Troubleshooting efforts at the time showed that the
'ifferential pressure switch behaved erratically.
I8C technicians exercised the switch a number of times until it appeared to function normally.
It was then reported to plant management that the functional checks of the switch were satisfactory.
It,appears the troubleshooting efforts were not adequate in that sufficient effort was not made to determine the cause of the erratic behavior.
In response to this, a
memo addressed to all personnel was sent out by plant management to reemphasize the need to adequately address the root cause of unusual characteristics or failures of critical components.
The inspector discussed with plant management that plant personnel continue to seem willing to proceed under uncertain circumstances and that continuing emphasis to plant personnel is required to reverse this attitude.
The second area of concern was related to the failure of the steam bypass system to function so as to mitigate the effects of the loss of turbine load, thus resulting in a reactor trip on high pressurizer pressure.
Three of eight steam bypass valves did not properly respond during the event.
In response to past problems with the reliability of the steam bypass valves, the licensee had implemented design changes on all valves in Units 2 and 3 ~
However, these changes had not been fully implemented in Unit 1.
The lack of timeliness of the implementation of changes in Unit 1 was discussed with the licensee, noting in particular that Unit 1 continues to have a much larger backlog of work items than Units 2 and 3.
The licensee indicated that additional resources were planned for reducing the maintenance backlog in Unit 1 and for assuring the implementation of design changes already implemented in the other two units.
'o violations of NRC requirements or deviations were identified.
Reactor Tri Followin Generator S nchronization - Unit 1 (93702 On August 27, 1988, a reactor trip on Low Steam Generator No.
1 Level occurred from approximately 12X power.
The sequence of events leading to this trip were as follows:
The mai,n generator output breakers were closed onto the grid and the generator was loaded to approximately 80 MWe, which was
MWe more-than directed by procedure.
.This caused a decrease in primary temperature to less than 552 degrees F, which is the minimum temperature for criticality required by Technical Specifications.
This prompted operators to compensate by diluting and withdrawing CEAs, as well as reducing turbine load.
These combined actions overcompensated for the low temperature condition, which had reached a minimum of 548 degrees F,
and, caused a large increase in primary temperature, which resulted in Steam Bypass Control Valves (SBCV)
opening as designed.
Contributing to the wide temperature swing was
, the low value of the Moderator Temperature Coefficient (MTC) due to the beginning-of-cycle conditions.
-The temperature increase and resulting steam demand from the SBCVs raised reactor power to approximately 17X where the Feedwater Control System (FWCS) automatically caused a swap over of main feed valves from the smaller downcomer control valves, which were being used to feed the steam generators, to the large economizer control valves, which prior to this event were correctly isolated in accordance with the procedure.
With the economizer isolation valves closed, the swap over had the net result of isolating all feed to the steam generators.
Operators regained manual control of the downcomer valves and established adequate feed flow at a lower than normal steam generator 'level.
The operators failed to notice the increasing main feed pump speed and discharge pressure occurring in response to the low steam generator level.
The small size of the downcomer feed lines allowed a.buildup of feed pressure to reach the high pressure trip setpoint, tripping the main feedpump.
Operators were then unable to restart the pump because they failed to return the speed control to zero, which is required to regain control of the pump control system.
The reactor subsequently tripped on low steam generator No.
1 level.
Operators stabilized the plant in Mode 3.
The licensee's post trip review of this event identified twelve concerns, eight of which were related to operator performance.
Of these eight concerns, seven were resolved by additional procedural guidance or an intent to evaluate possible procedural changes.
Only one of these eight concerns, the operator's overcompensation with CEAs, included a commitment to evaluate the crew's teamwork in mitigating the transient.
This action was due within thirty days of the report.
The overwhelming thrust of the licensee's corrective actions, as specified in the post trip review report, was toward procedural evaluation and revision.
This response appeared inconsistent with the human performance issues raised by this event.
The inspector concluded that the licensee's post trip review report inappropriately characterized most of the twelve concerns primarily as procedural deficiencies.
The licensee has, in the past, used a
Human Performance Evaluation System (HPES) to systematically assess operator performance deficiencies.
Licensee management did not initially consider using this system to
analyze the event.
As a "result of inquires into this matter by NRC inspectors, the licensee agreed to complete a
HPES evaluation of the event.
This evaluation will be reviewed upon completion.
(Inspector Followup Item 528/88-29-01).
No violations of NRC requirements or deviations were identified.
Letdown Containment Isolation Valve Post-Maintenance Retest - Unit 2.
71707 Letdown containment isolation valve 2CHB-UV-523 experienced two spurious closures during this report period.
Troubleshooting and Corrective
'aintenance included replacement of the control room hand switch and the actuating relay, both of which are electrically connected to the ESFAS relay K-204, which acts to shut the valve during a CIAS.
Technical Specification 4.6.3. 1 requires that the valve be demonstrated operable prior to returning it to service following replacement work on the control circuit.
The inspector questioned whether. the retest required by the Technical Specification must include a demonstration of automatic valve closure upon a CIAS condition.
The licensee's response was that since the replaced relay and switch were physically located apart from the K-204 relay, such that no modification of the CIAS function could
.
have occurred, it was sufficient to retest the valve by stroking it from the control room hand switch.
The inspector considers this an interpretation of Technical Specifications which must be consistently applied to all maintenance associated with control circuits of ESF components.
This item will be left open pending further information from the licensee regarding their method for ensuring consistency in interpreting this and similar Technical Specifications (Inspector Fol 1 owup Item 529/88-28-01).
No violations of NRC requirements or deviations were identified.
Reactor Power Cutback - Unit 2.
On September 6, 1988, while operating at 100K power, Unit 2 experienced a
Reactor Power Cutback to 52K power due to the loss of the "B" main feedwater pump.
Maintenance had been authorized on the "A" main feedwater pump minimum flow recirculation (miniflow) valve under work order 00311996.
The work order called for isolation of service air to the control circuitry to
.allow replacement of a line oiler.
The work order did not specify that isolation of the service air would cause the miniflow valve to fail open.
When the mechanic isolated the service air to the miniflow valve, the valve failed open reducing the suction pressure of both feedwater pumps.
The low suction pressure trip of the main feedwater pumps are time delayed 10 and 15 seconds for the "B" and "A" pumps respectively.
After 10 seconds the "B" main feedwater pump tripped causing an increase in suction pressure, such that the "A" pump time delay did not trip the second pump.
The licensee is conducting Special Plant Engineering Evaluation Report (SPEER) 88-02-0085 on this incident.
The inspector's investigation into
this event determined the work order did not specify the appropriate precautions to the mechanics.
Also, the schematic drawing included in the work package was sufficiently complex to have warranted an explanation from engineering as to the operation of the trip circuitry.
The inspector discussed with unit, site, and corporate management, the need for the planner/coordinators'to provide sufficient instructions in the work order and for planner/coordinators, operations maintenance and other groups to solicit the assistance of the system engineers in the interpretation of diagrams not commonly used by those groups, rather than assuming they know how to,interpret such drawings and symbols.
Additionally, it was emphasized that this is another example of poor planning and control of work.
No violations of NRC requirements or deviations were identified.
Failure To Perform ualit Control Hold oint - Unit 2.
An allegation was received by Region V that a guality Control (gC)
holdpoint had been falsified (RV-88-A-0037). It was alleged that a
Uni't 2 gC inspector did not personally inspect a gC holdpoint that he signed.
The inspector reviewed the gC holdpoint in question and found that holdpoint to be a verification that Zone III Housekeeping was closed and Zone IV Housekeeping was set.
No further acceptance criteria was specified as to how to conduct this verification.
A previous gC holdpoint specified Zone III Housekeeping could be verified by logs or a walkdown of the Zone.
The Zone III closeout verification was completed by several gC inspectors working over a week period to ensure all material and personnel logged into the Zone III control point had been properly reconciled as no longer being in the area.
At the time the gC inspector signed the holdpoint, to the best of his knowledge the other gC inspectors had completed their portions of the log review without any discrepancies.
Subsequently, it was brought to the attention of the gC inspector and licensee management that a potential existed for portions of the Zone III log to have been missed.
The licensee directed a
complete reverification of the log and the gC inspector who signed the holdpoint withdrew his signature until the potential problem could be resolved.
The reverification was completed and confirmed that no problems existed with the first verification.
The licensee had documented the entire process on gC monitoring reports.
The inspector concluded that no falsification existed since the acceptance criteria did not specify how to perform the verification, the gC. inspector had made a reasonable attempt to ensure the verification was accomplished and reverification did not identify any new problems.
The allegation is considered closed.
The NRC inspector did point out to the licensee that gC holdpoints should include more detailed acceptance criteria.
The inspector also pointed out that trying to reconcile a control point log that spanned nearly the entire refueling outage appeared to be a cumbersome task and a shiftly or daily verification may be more appropriat No violations or deviations were identified.
Si noffs Not Made as Maintenance.Was Performed - Unit 2.
While conducting a tour of the Unit 2 turbine building the inspector observed mechanical maintenance being performed on the turbine cooling water pump, a non-safety related pump.
The workers indicated to the inspector the portion of the procedure they were performing; however, none of the previously performed steps in the procedure had been initialed as required by the licensee's Conduct of Maintenance procedure, including the first step, which requires the clearance to be verified.
The inspector discussed this finding with the worker's Foreman, the Maintenance Manager and Plant Manager.
This was identified as another poor practice in the control and execution of maintenance.
The Unit 2 Maintenance Manager has subsequently discussed-this occurrence with all maintenance supervisors.
The results of the meeting was termed positive by the licensee in that the interpretation of portions of the Conduct of Maintenance procedure were clarified for the workers in a non-punitive forum.
Also, on a regular basis, part of the weekly safety meeting will be devoted to feedback between the workers and management with regard to intepretation or clarification of procedures and policies.
No violations or deviations were identified.
Inaccuracies in Calculation of Estimated Critical Conditions -
Unit 3 71707 On August 16, 1988, the control room operators halted the startup of the Unit 3 reactor, when upon reaching the estimated critical rod position which had been calculated using procedure 720P-9RX01, Revision 2, Calculation of Estimated Critical Conditions, the reactor had not gone critical nor had the expected increase in neutron count rate occurred.
The operators reinserted the control rods by an amount equal to 500 pcm of reactivity, while the accuracy of the Estimated Critical Conditions (ECC) could be verified with reactor engineering.
In consultation with reactor engineering, it was determined that the ECC calculated using the current operating procedure 720P-9RX01, did not include the effects of Samarium after a reactor shutdown.
By not doing so, the ECC calculation was biased in such a way that the reactor would not go critical in most cases without the additional withdrawal of control rods by an amount of at least 125 pcm beyond the estimated critical rod position.
Although the licensee's reactor startup procedures allow for criticality to occur (within) plus or minus 500 pcm of the ECC without requiring additional evaluation, the lack of precision in the calculation of the ECC caused the operating crew to act conservatively in this case and halt the reactor startup when neutron count rate did not increase as expected.
Subsequently, the licensee has modified procedure 720P-9RXOl such that Samarium is included as a factor in the calculation of the ECC.
On August 18, 1988, the Unit 3 reactor was successfully started up with actual critical conditions differing by only 100 pcm from those calculated using the revised procedure.
The inspector expressed concern that despite the early criticality event which occurred in Unit 1 in May, 1988 and subsequent concerns expressed by the NRC, that weaknesses still
appeared to exist in,the licensee's reactor startup procedures.
The inspector encouraged the licensee to ensure the completeness of corrective actions taken in response to plant events.
No violations of NRC requirements or deviations were identified.
'
Tem orar Instruction TI-15-93 - Verification of ualit Assurance Re uest Re ardin Diesel Generator Fuel Oil SIMS Item MPA A-15
.
This temporary instruction deals with the veri'fication that emergency diesel generator fuel oil is included in the licensee's guality Assurance (gA) program.
The inspector confirmed that the licensee treats the emergency diesel fuel oil as safety related material.
Several purchase orders were noted to be marked "gR" to indicate the material was quality related.
The purchase orders also contain the ASTM specifications which the oil must meet.
A plant procedure, 74CH-9XC46 "Diesel Generator Fuel Oil Receipt and Verification," has been written to control the sampling and analysis of new fuel oil.
A surveillance test, 74ST-9DFOl, "Diesel Generator Fuel Oil Surveillance Test,"
has also been written to verify that the quality of the diesel fuel meets the acceptance criteria specified in Technical Specifications.
Based on these observations, the inspector considers this item closed for all 3 units.
No violations of NRC requirements or deviations were identified.
Followu Licensee Event Re ort - Units 1 2 and
92700 The following LER was reviewed by the inspector.
Based on the information provided in the report, it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below listed LER is considered closed.
Unit 1 LER NUMBER DESCRIPTION 87"14-LO Reactor Trip During Maintenance Pump Turbine Testing.
No violations of NRC requirements or deviations were identified.
Review of Periodic and S ecial Re orts - Units 1 2 and
90712)
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 validity of the reported information.
Within the scope of the above, the following reports were reviewed by the inspecto Unit 1 o
Monthly Operating Report for July and August, 1988.
Unit 2 o
Monthly Operating Report for July and August, 1988.
Unit 3 o
Monthly Operating Report for July and August, 1988.
No violations of NRC requirements or deviations were identified.-
17.
Exit Meetin The inspector met with licensee management representatives periodically during the inspection and held an exit on September 22, 1988.
During the exit meeting, the inspector emphasized the items of poor control and execution of work of Sections 9,
10 and 1 '