IR 05000528/1989036
| ML17305A377 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 10/25/1989 |
| From: | Richards S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305A375 | List: |
| References | |
| 50-528-89-36, 50-529-89-36, 50-530-89-36, GL-88-17, IEIN-86-005, IEIN-86-5, IEIN-88-047, IEIN-88-47, NUDOCS 8911130107 | |
| Download: ML17305A377 (58) | |
Text
Re ort Nos.
Docket Nos.
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
50-528/89-36, 50-529/89-36 and 50-530/89-36 50-528, 50-529, 50-530 License Nos.
NPF-41, NPF-51, NPF-74 Licensee:
Arizona Nuclear Power Project P.
0.
Box 52034 Phoenix, AZ. 85072-2034 Faci lit Name:
Palo Verde Nuclear Generating Station Units 1,
8
Ins ection Conducted:
August 7 through September 10, 1989 Inspectors:
Approved By:
T. Polich, Senior Resident Inspector D.
Coe, Resident Inspector J.
Ringwald, Resident Inspector C. Myers, Resident Inspector, Rancho Seco P.
squalls, Resident Inspector, Rancho Seco S.
Richards, Chief Reactor ProjectsSection II t o-2S'- 8'f Date Signed Ins ection Summar Ins ection on Au ust 7 throu h Se tember
1989 (Re ort Nos.
50-528/
89-36 50-529/89-36 and 50-530/89-36)
Areas Ins ected:
Routine, onsite, regular and backshift inspection by the three resident inspectors, and other inspectors from the Region V
staff.
Areas inspected included: previously identified items; review of plant activities; engineered safety feature system walkdowns; monthly surveillance testing; monthly plant maintenance; loss of spent fuel pool level - Unit 1; capacitor bank fire - Unit 1; loss of power load shed Unit 1; inadvertent diesel generator start - Unit 1; discharge of carbon dioxide in "A" train switchgear room - Unit 1; expired flammable storage permit not removed - Unit 1; pre-job briefings Units 1 and 2; review of incident investigation report 2-2-89-001 of the "reactor trip of July 12, 1989" - Unit 2; surveillance procedure steps not signed Unit 2; low temperature overpressure (LTOP) relief valve lapse of surveillance interval - Unit 3; fire protection evaluation for trailers placed next to the condensate storage tank (CST) - Unit 3; overfill of reactor coolant system (RCS) during safety injection system valve manipulations - Unit 3; incorrect radiation 'monitor alarm setpoint - Unit 3; TI-15-101, loss of decay heat removal (generic letter 88-17) - Units 1, 2, 3; main steam safety valve (MSSV) blowdown ring settings
- Units 1, 2, and 3; allegation followup (RV-89-A-0031); review of licensee event reports-Units 1, 2 and 3; and review of periodic and special reports
- Units 1,
and 3.
89lii30l07 8'91025 PDR ADOCf( 05000528 pNU
During this inspection the following Inspection Procedures were utilized:
2515/10, 30702, 30703, 61701, 61726, 62703, 64704, 71707, 71710, 90712, 92701, 93702, and 94600.
Safet Issues Mana ement S stem SIMS Items:
None Results:
Of the eleven areas inspected, four violations were identified.
These violations pertained to failure to control spent fuel pool level at Unit 1 after a similar problem at Unit 3, the failure to follow procedures when resequencing steps in an operating procedure at Unit 3, the failure to translate design calculations into plant procedures, and the fai lure to complete corrective action at Unit 3.
General Conclusions and S ecific Findin s
Si nificant Safet Matters:
None Summar of Violations:
Summar of Deviations:
0 en Items Summar
Four None ll items closed 6 items left open and 8 new items opene DETAILS Persons Contacted:
The below listed technical and supervisory personnel were among those contacted:
Arizona Nuclear Power Pro ect ANPP
"R. Adney,
"J. Allen,
"R. Badsgard,
"J. Bailey, B. Ballard,
- C. Bel ford,
"H. Biel ing,
- T. Bradi sh, P.
Brand jes,
"F.
Buckingham,
- P.
Caudi 1 1, W.
Conway,
- D. Crozier,
"R. Flood,
- F. Garrett,
~D.
Gouge,
- D. Hackbert, J.
Haynes,
- D. Heinicke, P.
Hughes,
~W. Ide,
"J. Kirby,
"J.
LoCicero,
- W. Marsh,
"D. Oakes,
"J.
Rei 1 ly,
- C.
Roger s, C.
Russo,
- J. Scott,
- T. Shriver,
"G. Sowers, Plant Manager, Unit 3 Relief Plant Manager Nuclear Engineering Supervisor Vice President, Nuclear Safety 8 Licensing equality Assurance Director Fire Protection Supervisor Emergency Plan/Fire Protection Manager Compliance Supervisor Central Maintenance Manager Operations Manager, Unit 2 Site Services Director Executive Vice President
- Nuclear Fire Protection Captain Assistant Plant Manager, Units 2 and
Risk Management, Senior Engineer Operations Manger, Unit 3 guality Audits 8 Monitoring Supervisor Vice President, Nuclear Production/Site Director Plant Manager, Unit 2 Radiation Protection 8 Chemistry Manager Plant Manager, Unit 1
.
Director, Nuclear Production Support Independent Safety Engineering 'Manager Plant Director El Paso Electric, Engineer Standards and Technical Support Director Licensing Manager Assistant guality Assurance Director Operations Manager, Unit 1 Compliance Manager Engineering Evaluations Manager The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
- Attended the Exit meeting held with,NRC Resident Inspectors on September 14, 198 l '
II f
l l
t i
2.
Previousl Identified Items - Units 1
and 3 (92701 92702 Closed Followu Item 529/88-28-01:
"Letdown Containment Isolation Valve Post-Maintenance Retest" - Unit 2.
This item was opened following the inspector's questions regarding the licensee's interpretation of Technical Specification Surveillance Requirement 4. 6. 3. 1, which requires containment, isolation valves to be "demonstrated OPERABLE" following maintenance or repair to the valve, actuator, or control circuitry.
The inspector reviewed the licensee's Technical Specification Interpretation (TSI) 3.6.3.0-13-04-00, which was approved by the Plant Review Board (PRB)
on July 19, 1989, and determined that if the control circuits of containment isolation valves are repaired such that components which affect the Engineered Safety Features (ESF) function of the valve are replaced or modified, the guidance within the TSI would require completion of the applicable Surveillance Test as part of the post-maintenance retest.
The inspector concluded that the guidance was appropriate.
This item is closed.
(Closed Unresolved Item (529/89-21-01:
"Excess Flow Check Valves for Emer enc Diesel Generators"
- Unit 2.
Excess Flow Check Valves (XCV's) are used on the Diesel Generator (DG) System, among others, to separate seismically qualified pipe from downstream non-seismically qualified pipe or instrument tubing.
Should a downstream break occur, XCV's are designed to shut, thereby preserving the safety system integrity.
ANPP engineering calculation 13-MC-ZZ-704 represented in its summary that even if both DG XCV's stuck full open following a Safe Shutdown Earthquake (SSE),
the resulting flow rate and air loss from the DG starting air banks would not remove the five-start design capability within about the first 30 minutes.
The five-start design criteria is specified in PVNGS FSAR Section 9.5.6. 1 A and B.
Based on this conclusion, alarm response procedure 41AL-1RK7C, Window 7C14A (Seismic Occurrance),
requires that, following an SSE, an operator is to immediately (and within 30 minutes)
shut the DG XCV isolation valves.
However, the inspector identified that the actual calculation 13-MC-ZZ-704 clearly shows that the DG loses all start capability'ithin 30 minutes under the above conditions.
In fact, Table 2 of this calculation specifies that DG XCV isolation valves must remain closed except when taking instrument readings.
The licensee's failure to correctly translate an engineering calculation into operating procedures is an apparent violation of NRC requirements (529/89-36-01).
In June 1989, when the inspector questioned the appropriateness of the alarm response procedure and the validity of its basis calculation, the licensee chose to isolate the XCV's in question prior to the restart of Unit 2 in July 1989.
At that
time the licensee committed to a further review of this calculation and development of a long term resolution for XCV's in the DG and other systems.
On September 6, 1989, during a walkdown of the Unit 3 Emergency Diesel Generators (EDGs), the inspector noted that the XCV's were not isolated and that operations personnel considered the DG's operable.
When the XCV issue was previously addressed in Unit 2, the Unit 3 DG's were both inoperable at that time.
When the Unit 3 DG's were subsequently declared operable, the licensee failed to carry through their interim corrective action in Unit 3.
The failure to complete interim corrective action for all affected units is an apparent violation of NRC regulations (530/89-36-01).
The inspector checked Unit 1 and noted that DG XCV's were appropriately isolated.
(Closed Followu Item 530/88-41-02
- "Dro ed Part Len th Control Element Assemblies PLCEAs)" '- Unit 3.
Following two dropped PLCEA events one day apart, the licensee determined that Control Element Drive Mechanism (CEDM) gripper coil voltages were higher than the values specified in the technical manual.
Because several coils are used on each CEDM and during Control Element Assembly (CEA) movement are energized in an overlapping sequence, a high voltage condition may cause an over current condition which could trip the CEA power supply breaker.
Following these events, the licensee adjusted all CEDM coil voltages in all three units and committed to developing a Preventive Maintenance procedure for periodic checking of important CEDM parameters.
The inspector reviewed newly approved procedures 36MT-9SFll,
"CEDMCS Power Supply Calibration and Lamp Test,"
and 36MT-9SFl2,
"CEDMCS Logic Housing Coil Voltage Calibration."
The inspector concluded that these procedures met the intent of the licensee's commitment.
This item is closed.
(0 en) Followu Item (530/89-21-02
- "Loss of S ent Fuel Pool Level" - Unit 3.
(Designated 530/89-21-01 in error in report 89-21).
Following a-loss of control of Spent Fuel Pool level-in Unit 3, licensee management indicated that a broad review of system status control requirements would be conducted.
Since then, several other valve alignment problems have occurred, including a Unit 1 Spent Fuel Pool level loss to below Technical Specifications minimum level.
These issues are addressed elsewhere in this report.
This item remains open until the licensee completes consideration of alternatives to maintaining valve and system status information which can be effectively used by operations personne en) Part 21 Items 88-18-P:
"Crackin of Slides in Anchor/
Darlin Valves" '- Units 1 2 and
This Part 21 notification involved a problem of cracked slides in four-way valves furnished on the actuators for Main Steam Isolation Valves (MISVs).
By letter of March 16, 1988, the MSIV manufacturer (Anchor/Darling Valve Co.) reported to the NRC and the industry that certain four-way valves, furnished on the actuators of the MSIVs were subject to developing cracks in slide material in the valve.
Anchor/Darling concluded that the cracking resulted from the brazing heating of the slide material by the four-way valve manufacturer (Teledyne Republic).
Anchor/Darling informed affected licensee's how to detect a cracked slide by testing the four-way valves for leakage.
The inspector followed up on the licensee's actions in response to the identified deficiency.
The inspector found that the licensee had initiated Engineer'ing Evaluation Request EER-88-SG-123 to evaluate the extent of the problem and determine appropriate corrective actions.
. This item will remain open pending review of the licensee's evaluation.
(0 en NRC Information Notice No. 88-47:
"Slower Than Ex ected Rod Dro Times".
The inspector reviewed the Nuclear Licensing Department's closure memorandum 162-02974-FPC/NLT dated January 30, 1989.
The memo stated that the increased holding coil decay time of 0.3 seconds due to dropping all rods simultaneously, instead of individually, as is done during rod testing, when applied to the slowest drop time data available, did not increase rod drop times beyond that assumed in the Safety Analysis and remained within the Technical Specification limit of 4. 0 seconds for 90%
insertion.
The inspector concluded that this analysis appeared adequate for the most limiting (slowest)
rod drop time known at that time.
However, the inspector questioned how continued compliance with the 4.0 second limit would be met for future rod testing since no change had been made to the surveillance acceptance criteria of 73ST-9RX01,
"CEA Drop Testing".
No provision was made for the possibility that future drop tests may result in even slower CEA drop times, thus requi ring renewed consideration of the 0.3 second delay.
The inspector considered that the effect of the CEA testing methodology on the assumptions used by Technical Specifications for the drop time limit is clearly not resolved until all future such testing considers this effect.
The licensee stated that further review would be conducted.
This item will remain open pending a review of the licensee's respons (Open) Part 21 Item (89-02-P):
"Two Deficiencies in Limitorque Valve 0 erators" - Units 1 2 and 3.
This Part 21 notification involved two deficiencies identified in certain models of Limitorque valve operators which were supplied for safety related applications.
By letter of November 3, 1988, the manufacturer (Limitorque Corporation) reported to the NRC and affected nuclear utility customers that a
common mode defect existed in Limitorque supplied SMB-000 and SMB-00 valve actuators.
As a result of their evaluation of torque switch failures experienced in the industry, Limitorque concluded that long term post mold shri nkage of the plastic (Melamine)
used in their older style torque switches caused the failures.
Limitorque recommended expeditious replacements of all the affected torque switches with components of a newer design, not subject to the deficiency.
In addition, by separate letter of November 3, 1988, Limitorque reported that elevated temperatures result in a degradation in the performance of certain size DC motors.
Limitorque recommended licensee's review their applications of the affected motor sizes to ensure they can develop full rated torque under the applicable temperature conditions.
The inspector followed up on the licensee's actions in response to the identified deficiencies.
The inspector found that the licensee had initiated engineering evaluation requests EER-88-XE-015 to evaluate the extent of the problems and determine appropriate corrective actions.
This item will remain open pending review of the licensee's evaluations..
0 en Part 21 Item (89-04-P
"Coo er Diesel Generator Turbochar er Post-Lube Pilot Valve" - Units
2 and 3.
This Part 21 notification involved the incor rect installation of non-safety related components in the safety related Emergency Diesel Generator (EDG) system~
By letter of March 16, 1989, another licensee (Niagra Mohawk)
identified to the NRC that the post-lube pilot valve originally installed on the turbocharger of their two Cooper Energy Services emergency diesel generators lacked sufficient documentation to qualify their use in the safety related application.
This letter supplemented a previous letter of November 21, 1988, reporting a deficiency in the safety classification of a replacement valve for the post-lube pilot val ve.
The post-lube pilot valve is utilized to control air pressure to the post-lube control valve, which in turn, controls the
lube oil to the bearings of the turbocharger of the diesel generators.
During startup of the EDG, air pressure on the post-lube control valve is vented through the post-lube pilot valve, thereby providing lubrication to the bearings.
Failure of the pilot valve could cause turbocharger failure, preventing the EDG from achieving full rated power.
t The inspector followed up on the licensee's actions in response to the identified problem.
The inspector found that the licensee had not yet received notification of the problem from either the manufacturer or the industry.
In response to the inspector's inquiry, the licensee initiated an Engineering Evaluation Request (EER) to evaluate the applicability of the problem and identify any corrective actions necessary.
This item will remain open pending future review of the licensee's evaluation.
0 en) Enforcement Item (50-528/89-02-03):
"Interface with Phoenix Fii e De artment This item was previously reviewed in inspection report 50-528/89-33, and closed out in error.
This item is re-opened and remains open pending the issuance of a notice of violation and a review of the licensee's response to the notice of violation.
3.
Review of Plant Activities (71707 71710 93702)
i Unit 1 Unit '1 remained in a refueling outage with the core off loaded during the inspection period.
Unit 2 Unit 2 began the inspection period in Mode 1 at lOOX power and remained at power until September 6, 1989, when an orderly shutdown of the unit was directed by licensee management so that Main Steam Safety Valve operability questions could be resolved.
The unit entered Mode 4 at 2:26 AM, on September 8,
1989, and remained in that Mode until the end of the inspection period.
Unit 3 Unit 3 remained in a refueling outage and transitioned from Mode 6 to Mode 5 on August 15, 1989.
Plant Tours The following plant areas at Units 1, 2 and 3 were toured by the inspector during the inspection:
Auxiliary Building Containment Building Control Complex Building Diesel Generator Building Radwaste Building Technical Support Center Turbine Building Yard Area and Perimeter The following areas were observed during the tours:
0 eratin Lo s and Records Records were reviewed against Technical Specification and administrative control procedure requirements'.
Monitorin Instrumentation Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
3.
observed for conformance with 10 CFR 50.54.(k), Technical Specifications, and administrative procedures.
E ui ment Lineu s
Various 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 the conduct of partial system lineups.
The inspector observed a
portion of 430P-3RC02; RCS Fill and Vent, at Unit 3.
E ui ment Ta in Selected equipment, for which tagging requests had been initiated, was observed ta verify that tags were in place and the equipment was in the condition specified.
General Plant E ui ment Conditions Plant equipment was observed for indications of system leakage, improper lubrication, or other conditions that would prevent the systems from fulfillingtheir functional requirements.
7.
Fire Protection Fire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures.
Several problems were noted with fire protection personnel or equipment (See Sections 9, 11, and 12).
"'""K for conformance with Technical Specifications and admin-istrative control procedures.
~securit Activities observed for conformance with regulatoiy requirements, implementation of the site
i
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 areas was evaluated with respect to controlling the spread of surface and airborne contamination.
The inspector noted the presence of non-work related reading material (i.e.
a personal computer supply catalog)
left in the Unit 3 Engineered Safety Features chiller room, and debris (i.e.
a loose section of tygon hose) in the near vicinity of the operating B Spray Pond pump.
Both items were brought to the attention of the Unit 3 Operations Manager, who acknowledged the inspector's concern regarding formality in operations and loose debris near safety related equipment.
11.
Radiation Protection Controls Areas observed included control point operation, records of'icensee'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.
No 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 functions.
Accessible portions of the following systems were walked down during this inspection period.
Unit 1
~
0
"A" 8; "B" Safety Injection Tanks Containment Integrity (Personnel Hatches)
Unit 2 o
"A" 8; "B"
I
Unit 3 Emergency Diesel Generators
>>A>> 5 >>B
. Essential Spray Ponds
>>A>>
>>B>>
Safety Injection Tanks Containment Integrity (Personnel Hatches)
No violations of NRC requirements or deviations were identified.
5.
Monthl Surveillance Testin
- Units
2 and 3 (61726)
Selected 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'echnically 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.
Specifically, portions of the following survei llances were observed by the inspector during this inspection period:
Unit 1 Procedure Descri tion o 36ST-1SM01 o 36ST-1SM02 o 71ST-lDG01 Seismic Monitoring Functional Test Seismic Monitoring Calibration Test Integrated Safeguards Surveillance Test Unit 2 Procedure o 36ST-9SB22 o 42ST-2DG02 o 77ST-2SB12 Descri tion Plant Protection System Input Loop Calibration Steam Generator No.
1 Low Level.
Emergency Diesel Generator Monthly Functional Test Control Element Assembly Calculator No.
Functional Test o 42ST-2SG04 Atmospheric Dump Valve Stroke Test Unit 3 Procedure Descri tion o 72ST-3RÃ09 Shutdown Margin No violations of NRC requirements or deviations were identifie II i
6.
Monthl Plant Maintenance
- Units 1 2 and
62?03)
a.
During the inspection period, the inspector observed and reviewed selected documentation associated with maintenance and problem investigation activities listed below 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, personne1 qualifications, and proper retesting.
The inspector verified that reportability for these activities was correct.
b.
Specifically, the inspector witnessed portions of the following maintenance activities:
Uni.t 1 Descri tion o
"B" Train Potter-Brumfield Relay Replacement o
MOVATS Testing o
Reactor Coolant Pump Overhaul Unit 2 Descri tion o
Maintenance on Unit 2 "B" Emergency Diesel Generator PSL-0008.
o
"A" Main Feedwater Pump Troubleshooting/Testing Unit 3 Descri tion o
Control Element Drive Mechanism Retermination o
Heated Junction Thermocouple Retermination 7.
Loss of S ent Fuel Pool Level - Unit 1 (93702 Recent valve alignment problems follow a long history of such problems at Palo Verde, in spite of licensee efforts to improve in this area and industry wide notifications of similar problems at other utilities.
On May 22, 1989, Unit 3 inadvertently transferred 9.5 inches of Spent Fuel Pool water into the transfer canal during a routine system realignment, due to an incorrectly statused valve on control room system prints.
This incident was documented in NRC inspection report 530/89-21.
On August 2, 1989, Unit 1 inadvertently transferred 15,000 gallons of Spent Fuel Pool (SFP) water into the transfer canal during a
routine system realignment.
Minimum SFP level during this event was
136 feet 8 inches, which is four inches below the minimum allowed by the Technical Specification LCO (3.9.11).
Level was restored within the applicable Action Statement time limit.
The SFP operating procedure, 410P-1PC01, did'not contain explicit directions to perform the desired evolution, which was to sluice water from the cask pit (separated from the SFP by a removable gate) to the containment transfer canal.
The operating crew performed a valve lineup in accordance with Operating Department Guideline (ODG) 1?,
System Status Control, which documents valve lineups for which there is no approved procedure.
The ODG-17 lineup used did not isolate the SFP from the intended gravity drain flow path.
As the lineup was being performed, when a flow path was created between the SFP and the transfer canal, the SFP siphoned into the canal.
Although operators used a system print to determine the required valve lineup, they did not recognize the need to isolate the SFP from the flow path.
Procedure 410P-1PC01 contained a caution (3.19) against the possibility of gravity flow between tanks with different levels, but fell short of identifying potential siphon paths or requiring specific actions such as isolating a desired flow path from all other water inventories.
The inspector noted that as a result of the Unit 3 SFP event of May 22, 1989, Unit 1 issued Night Orders dated May 25, 1989, which stated, in part,
"When an evolution is planned, sufficient valves which encompass the flow path must be actually verified to ensure that the water flows only from/through/to the desired portions of the system."
This was not accomplished during the evolution leading to the Unit 1 event.
The operators were not alerted to the SFP level decrease until the lo-lo level alarm activated at the Technical Specification minimum level of 137 feet.
The low alarm (at 137 feet 6 inches)
was not operating due to a wiring problem which had been identi fied in 1985, and a
DCP written, but not yet installed in Unit 1.
The system engineer had identified this problem earlier in the year and initiated a work order to complete the DCP during the present outage.
The DCP had not yet been installed at the time of this event.
Units 2 and 3 had installed the DCP during construction or star tup.
The licensee could not explain why the Unit 1 DCP had not been scheduled until it was pointed out by the system engineer.
The DCP was subsequently completed in Unit 1.
The inspector noted that following the Unit 3 SFP incident on May 22, 1989; a priority Instruction Change Request (ICR)
(No.
09585)
was submitted recommending improvements to procedures 4XOP-XPC01 for all units.
As of the end of this report period, this ICR had not been implemented due to a backlog of higher priority ICR's being worked and a down grade in priority of ICR No.
09585.
The inspector noted that NRC Information Notice 88-65 described circumstances of SFP drainage including mispositioned valves, inadvertent siphon paths, and inoperable level alarms which were all problems associated with the above Unit 1 and Unit 3 SFP events.
This notice had been closed out by the Nuclear Licensing Department as of July 21, 1989, and concluded that no procedural or hardware changes are recommended for PVNGS.
This conclusion apparently did
not acknowledge the several ICR's for the SFP system which had not been dispositioned.
The inspector noted that Independent Safety Engineering (ISE) issued an investigation report dated August 17, 1989, on the Unit 3 May 22, SFP event which concluded, among other things, that ODG-17 continues to not be effectively implemented, procedure 4XOP-XPC01 has 'human factors deficiencies, and a design change to the SFP system which incorporates additional check valves would be helpful.
Based on the above observations, the inspector concluded:
1)
Unit 1 operations management was not effective in implementing their stated requirement to control SFP evolution flow paths by closing boundary valves which. isolate non-desi red flow paths.
This is considered inadequate corrective action and a violation of NRC regulations (528/89-36-01).')
Procedures 4XOP-XPC01 (Series) failed to provide sufficiently detailed instructions for the desired evolution and failed to identify potential siphon or gravity drain paths.
3)
The licensee's control of DCPs was inadequate in that a 1985 DCP to correct a wiring deficiency had not been completed in Unit 1 and was not scheduled for work until this discrepancy was discovered by a system engineer in early 1989.
4)
The licensee missed opportuni,ties to avoid SFP level loss problems by n'ot taking effective action on an August 1988, NRC Information Notice No. 88-65, which described problems almost identical to the recent Unit 1 and Unit 3 SFP events, and by choosing to delay action on procedure change requests to 4XOP-XPC01 following the Unit 3 event.
5)
The ISE special investigation of the Unit 3 SFP event (89-01)
included independent engineering recommendations for SFP system design changes to preclude recurrence.
These were submitted for engineering review.
The licensee management acknowledged the inspector's comments.
The licensee further stated that PC system operating procedure ICR's were in the process of being reviewed.
The inspector will review the revised procedures when approved as part of the notice of violation followup.
8.
Ca acitor Bank Fire - Unit 1 (93702 On September 1, 1989, at 4: 18 p.m.
a fire was detected in a capacitor bank located in the switchyard.
The capacitor bank had been replaced the previous day and is associated with the Devers 525 KV line, one of five offsite 525 KV lines.
The fire escalated quickly due -to the non-PCB contaminated oil and the prevailing wind which caused the fire to spread to the adjacent capacitor bank.
The affected offsite line and the capacitor banks were isolated
l l
l
electrically and the onsite fire department responded quickly and contained the fire using foam.
Due to insufficient foam, the fire was not extinguished until 5:28 p.m. Initially, there were
gallons of Aqueous Film Forming Foam (AFFF) on the truck.
When this was exhausted, the fire crew asked for more foam from the warehouse since it was closer than the fire department trailer.
When they discovered that there was no additional foam in the warehouse, they got an additional 30 gallons from the fire department trailer.
With this foam replenishment, the fire was quickly extinguished.
There was no additional damage, no personnel injuries and no,impact on any of the nuclear units.
The inspector discussed the inadequate supply of foam with the licensee.
Although the'icensee has not committed to NFPA-ll the inspector noted the following:
No evaluation has been performed of the largest plausible fire where foam would be the suppressant of choice, to determine the appropriate quantity of foam to keep on hand.
No procedures existed to specify how the foam is to be acquired, stored or used.
No inventory or inspection requirements existed at the time of the fire.
The licensee asserted that since the fire truck, with it's foam applicator, was acquired after the fire protection program had been specified in the licensing process, it was merely an enhancement to their program and not required in their licensing commitments.
The inspector acknowledged this assertion and pointed out that this not withstanding, reasonable practice suggests that any addition to a fire protection program which fire fighters come to rely on should be embraced by the administrative program in existence.
Fire protection management stated-they would establish a warehouse minimum/maximum inventory of AFFF, and would review the need for formal procedures and inspection requirements for auxiliary equipment on the fire truck.
Additionally, at the exit meeting licensee mangement committed to documenting their corrective action program in the next few weeks by separate correspondence.
This item will remain open pending review of this correspondence (528/89-36-02).
Loss of Power Load Shed - Unit 1 93702)
On September 2, 1989, at 2: 37 a. m., with the unit shutdown and all fuel removed from the reactor vessel (less than Node 6) the Emergency Diesel Generator (EDG) sequencer module failed in the Engineered Safety Features (ESF) cabinet, which caused the load shed signal to all breakers of safety related buss PBA-S03 to lock in a permanent load shed state.
This caused a loss of. power on this buss, which was sensed by the EDG loss of power circuitry, resulting
in an auto start of the EDG.
The EDG started and restored power to the buss, but the sequencer did not sequence loads because it locked'ut all loads in load shed.
This resulted in the EDG running and powering it's buss with no external cooling water to the engine.
The EDG is rated for between 3 and 60 minutes running time without cooling water depending upon load.
The diesel was lightly loaded due to the sequencer problem during this event.
The operators manually shutdown the EDG sixteen minutes after it started.
The ESF panel containing the failed load shed module was turned off to clear the locked in load shed signals so that safety related buss PBA-S03 could be restarted from it's normal source.
The Control Room and Fuel Building Essential Ventilation Actuation System signals were also initiated due to the transient, but the required equipment did not actuate due to the locked in load shed signals.
After restoring power to safety related buss, PBA-S03 and restoring from the transient, the operators quarantined the ESF cabinet for troubleshooting.
The preliminary investigation revealed a severely damaged load sequencer module in the ESF panel.
The inspector determined that the operators correctly diagosed the problem and acted quickly to secure the EDG, which was running without cooling water.
The inspector further determined that a
previous 1985 concern with module overheating was not a factor in this event.
No violations of NRC requirements or deviations were identified.
10.
Inadvertent Diesel Generator Start - Unit 1 93702)
On September 7, 1989, an inadvertent diesel start occurred.
"The start was a result of an Auxiliary Feedwater Actuation Signal (AFAS-2), which resulted from an Instrument and Control (I8C)
Technician attempting to remove a jumper from the "B" Train Nuclear Steam Supply System/Engineered Safety Features Actuation System (NSSS/ESFAS)
cabinet.
The jumper had been installed to permit troubleshooting and repair of a ground detected in the cabinet.
The ground had been isolated to the K-309 relay coil, one of the Recirculation Actuation Signal (RAS) relays, but the relay had not been replaced due to delay in obtaining a replacement relay.
The jumper was being removed to permit Integrated Safeguards Testing.
Ordinarily, as a good I8C work practice, a temporary alligator clip jumper is installed prior to removing the spade lug jumper.
In this case, the work order did not require the use of the alligator clip jumper, and the I8C Technician and Foreman apparently failed to question this omission.
The inspector was concerned that the alligator clip jumper was not installed since a similar event occurred at Unit 3 on June 14, 1989.
The Unit 1 I8C Technicians, while aware of this prior event, did not take measures to prevent reoccurence.
This appears to be another
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t
example of the licensee's failure to execute an effective lessons learned program between units.
No violations of NRC requirements or deviations were identified Dischar e of Carbon Dioxide in "A" Train Switch ear Room - Unit 1 93702 On September 9, 1989, during the performance of 14FT-9FP08, an inadvertent discharge of C02 occurred in the "A" Train Switchgear room.
The Instrumentation and Control (I8C) Technician was lifting leads in the "B" Train Switchgear room C02 panel and apparently lost control of an unlanded lead when it came in contact with another terminal, thereby causing the discharge.
Since the discharge occurred immediately, there was no warning for anyone who may have been in the "A" Switchgear room.
Plant personnel.
donned self contained breathing apparatus (SCBA) and searched the "A" Switchgear room looking for individuals who may have been overcome by the C02.
There were no personnel injuries.
The inspector observed the panel and the leads which had been lifted.
Several of the leads in the panel were bare stranded leads without ring lug terminals.
The 18C foreman involved stated that a
DCN had been initiated prior to this event to install ring lugs on these leads but the work has yet to be completed.
The 18C Foreman also pointed out a concern for the steps in 14FT-9FP08, which currently restore the C02 panel prior to lining up the wintergreen scent flask.
This permits a short time "window" where a
C02 actuation could occur after the panel is restored to service.,
but before the wintergreen scent flask is lined up to warn people in the discharge area to leave.
Licensee management acknowledged the inspectors concern for personnel safety and the need to expidite the DCN to prevent reoccurrence.
No violations of NRC requirements or deviations were identified.
Ex ired Flammable Stora e Permit Not Removed - Unit 1 71707)
On September 10, 1989, the inspector found a flammable storage permit that had expired on March 2, 1989, still p'osted on a storage container on the roof of the Unit 1 Auxiliary Building.
This permit was the subject of a Notice of Violation in Inspection Report 528/89-30, yet fire protection personnel (fire watches)
who make routine rounds of the area did not identify and correct this discrepancy.
The inspector noted other flammable storage containers in Unit 1 had current storage permits posted on the containers.
The inspector questioned whether fire protection personnel had taken any corrective actions in response to the Notice of Violatio t (
t
The inspector was informed that a
new permit had been issued and not posted but was being kept by Unit 1 work control.
Although the inspector's concerns about corrective actions were addressed; the
" follow-up to remove an expired storage permit appears lacking.
The inattention of fire protection personnel on routine rounds to review posted flammable storage permits and failure to post permits on storage containers appears to be isolated to Unit 1, as the inspectors have not observed such problems at the other units.
No violations of NRC requirements or deviations were identified.
13.
Pre-Job Briefin s Units 1 and 2 (61726)
The inspector observed pre-job briefings for several Control Room evolutions.
o Unit 1 Integrated Safeguards Testing (73ST-1DG01, Step 8.7) on SIAS/CIAS/LOP.
The briefing addressed the evolution, division of responsibilities, and methods of communication but lacked a
discussion of anticipated possible problems and plans for dealing with them.
o Unit 2 Atmospheric Dump Valve Testing (42ST-2SG04).
The briefing consisted of reading through the procedure precautions and warnings, and the expected sequence of action.
Where the procedure included some cautions about possible unexpected results, the cautions were mentioned but there was no detailed discussion involving the operators sharing their experiences.
o Unit 1 "B" Train Safety Injection System Fill and Vent, restoring the system to Shutdown Cooling (410P-1SIOl).
The briefing began with the personal experience of the briefer describing a problem with this event in the past.
The briefing contained the type of anticipation of possible pitfalls which were absent in the two other briefings.
Station Procedure 40AC-90P02, Section 3.3.9,- requires a pre-job briefing for complex evolutions which includes a discussion of anticipate'd problems.
Discussions with the Unit 1 and 2 Operations Supervisors indicated that this sort of problem anticipation in pre-job briefings is encouraged and will be emphasized.
No violations of NRC requirements or deviations were identified.
14.
Review of Incident Investi ation Re ort 2-2-89-001 of the "Reactor Tri of Jul
1989
- Unit 2 (92700)
On July 17, 1989, licensee management completed a "Technical and Cross-t1anagement (PRB) Review" of the information associated with the Incident Inv'estigation of the Unit 2 reactor trip.
Based on this review of the concerns and corrective actions needed for restart, licensee management approved the restart of Unit 2 with the stipulation that all specified restart corrective actions be
completed prior to restart.
The reactor was restarted on July 21, 1989, and the final IIR was approved on August 14, 1989.
The inspector noted that the plant Transient Review Assessment form in the final'eport included the following assessments:
o Does the event require an inspection of the hydraulic and mechanical snubbers per Surveillance Requirement 4.7.9 (d)
YES or NO (?)
o
"
Was a CPC-LPD or DNBR trip received?
YES or NO (?)
In the event that either of the answers to these questions is YES, a
signature block is provided f'r an appropriate Manager or Supervisor to certify that the required inspection or analysis was completed.
Of the above two questions, the last one was answered YES and the required analysis was to determine if a Safety Limit had been violated.
The signature certification that a Safety Limit was NOT violated was dated July 28, 1989, seven days following the restart.
The inspector determined from discussions with appropriate.
licensee personnel and review of the IIR that the analysis had been completed and the results were available to the Plant Review Board.
The other signature block was also signed, indicating that no snubber inspection was required, and was also dated after restart.
The inspector concluded that although the required analyses were conducted prior to restart, the documentation designed to ensure a
thorough review of the plant transient which caused the trip was not complete when the PRB made the restart decision on July 17, 1989, and in fact, was not completed until several-days after restart.
The inspector noted that the licensee's procedure 79AC-OIP01,
"Incident Investigation Category 1 and 2 Incidents",
which was applied to this investigation, did not clearly specify the documentation that would be required to make a restart decision.
Based on the extreme importance of a rigorous and well documented review of the ci rcumstances surrounding a reactor trip prior to considering restart, the inspector concluded that the licensee's IIR procedures were not adequate in that they failed to itemize specific minimum documentation necessary to show a full and complete understanding of a reactor trip event prior to restart.
Licensee management acknowledged these concerns and committed to revising the IIR procedures accordingly.
These will be reviewed during a follow-up inspection once they are approved (529/89-36-02).
No violations of NRC requirements or deviations were identified.
15.
Surveillance Procedure Ste s Not Si ned Unit 2 (61726)
On August 3, 1989, the inspector observed the performance of Surveillance procedure 42ST-2AF02, "Auxiliary Feedwater Pump AFA-POl Operability Test, 4.7. 1.2 (a)
and (c), for the Steam Driven Auxiliary Feedwater Pump".
The inspector entered the Control Room
ly
with the test in progress.
When reviewing the procedure the inspector noted that no steps were initiated in the procedure for completion, nor was required data recorded.
Licensee investigation revealed that the operator was not filling in the steps because the previous steps were identical, and documented while performing an operations procedure to run the pump in conjunction with the surveillance.
The operator then filled in the completed steps on the surveillance procedure from data already taken on the operations procedure.
The inspector could find no requirement in licensee procedures which require step by step documentation of surveillance test performance as the step is performed, as they require be done in maintenance work by ANPP procedure 30DP-9MP01.
American National Standards Institute (ANSI) standard N18.7-1976, Section 5.2.2, to which the licensee has committed in their Final Safety Analysis Report (FSAR) and in their equality Assurance manual, states "If documentation of an action is required, the necessary data shall be recorded as the task is performed."
This problem was also identified in Palo Verde Nuclear Generating Station (PVNGS)
inspection report 89-24.
At the conclusion of that inspection on June 30, 1989, the licensee committed to change the procedural requirements.
The licensee stated that the changes had been completed by the end of the inspection period.
These changes will be. reviewed in a future inspection.
No example of a failure to perform a step in a surveillance procedure due to this programmatic omission was identified by the inspector.
No violations of NRC requirements or deviations were identified.
16.
Low Tem erature Over ressure (LTOP) Relief Valve La se of Sur-veillance Interval - Unit 3 93702)
On August 15, 1989, shortly after entering Mode 5, Unit 3 operations personnel were advised by Engineering that the required two LTOP reliefs (Technical Specification (TS) 3.4.8.3)
had exceeded their maximum allowed surveillance interval on August 11 and
respectively.
Plant conditions existing during the period of Limiting Conditions of Operations (LCO) noncompliance met the requirement of the applicable Action Statement in that one pressurizer safety had an installed spool piece under it, providing at least 16 square inches of RCS vent path.
Thus, TS requirements were met until the Action Statement was exited on August 18, 1989, following.successful in-place lift testing of the LTOP reliefs.
TS 3.4.8.3. requires operable LTOPs when the reactor vessel head is
"installed" and Tcold is less-than-or-equal-to 255 degrees F during cooldown or 295 degrees F during heatup.
According to the TS basis for this LCO, the conditions of applicability were chosen because, for temperature and temperature changes above those specified, during the worst analyzed case mass or energy addition to the RCS, the RCS would be protected from
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fracture by the pressurizer safeties.
Thus, below these temperatures, assuming maximum allowed heatup or cooldown rates and worst case mass or energy addition to the RCS, LTOP rel-iefs would be required to protect the RCS against fracture (meeting the requirements of Appendix G of 10 CFR 50).
This basis suggests that LTOPs are required 1) at all times while in Mode 5 (135 degrees F-210 degrees F), 2) whenever the vessel head is "installed" while in Mode 6 (less than 135 degrees F),
as well as 3) while in Mode 4 (210 degrees F - 350 degrees F) at less than the specified temperatures.
The licensee currently interprets "installed" to mean whenever the reactor vessel head is in place on the vessel such that the
square inch vent path, required by the Action Statement for inoperable LTOPs, does not exist.
However, since the head was installed on August 4, 1989, and the LTOP surveillance intervals lapsed on August 11 and 12th, and Unit 3 entered Mode 5 on August 15, it is clear that the licensee's surveillance program failed to ensure LTOP operability requirements were maintained.
It was coincidental that the RCS was adequately vented throughout this time and thus protected RCS integrity from analyzed events.
The inspector reviewed the licensee'
Surveillance Testing Program procedure, 73AC-9ZZ04, and related procedures and noted the following.
The Survei ll.ance Program Control Group (SPCG) is responsible for tracking and scheduling all ST's with weekly or longer performance intervals.
However, they were not tracking 73ST-9ZZ19/20, which included the LTOP surveillances because= the date of the last satisfactory LTOP surveillance had not been entered into the computer tracking program due to an oversight.
The result of this omission was the following default. message which appeared on the monthly ST schedule:
"This Surveillance Test not scheduled at the request of the responsible performance group".
This statement had the net result of eliminating this surveillance test from SPCGs tracking system.
After the surveillance interval had lapsed, the performance group supervisor discovered the error while reviewing the impact of the recent Unit 3 Mode change (6 to 5) on the ability to do in-place testing of LTOP reliefs.
The inspector further noted that the controlling procedure, Surveillance Testing, 73AC-9ZZ04, was weak in that it lacked specific instructions on how data entry into the Monthly Master ST schedule would be controlled.
In addition, Surveillance Procedures 73ST-9ZZ19/9ZZ20 included other primary system pressure relief valves in addition to LTOPs.
However, these valves had a five year periodicity requirement whereas the LTOPs had an 18 month requirement.
The inspector concluded that this made the scheduling of 73ST-9ZZ19/9ZZ20 highly susceptible to errors such as this one.
I The inspector noted that 73ST-9ZZ19/20 status was not verified as part of the Mode Change Checklist for Mode 6 to Mode 5, 430P-3ZZ11, Appendix A.
However, as noted above, LTOP operability requirements are not entirely dependent on Mode but rather on plant conditions
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within a Mode (i.e.
head "installed" in Mode 6).
However, these surveillances were checked on checklists for Mode 5 to 4, 4 to 3,
to 2, and 2 to 1.
The inspector verified that LTOPs were placed in service at the appropriate plant condition per procedure 430P-3ZZ10,
"Hot Standby to Cold Shutdown Mode 3 to Mode 5.
The inspector concluded that the surveillance interval'tracking system did not appear to accommodate conditional surveillance requirements such as LTOP's.
The inspector noted that although the SPCG was not tracking the LTOP surveillance procedure, the performance group (Section XI engineers),
was tracking the individual valves required by 73ST-9ZZ19/20 to be Section XI tested every five years.
This group knew the LTOP's were due during this outage, but did not regard the LTOP surveillance interval lapse as a problem because of a mistaken belief that LTOPs were not required until Mode 4, based on the Mode change checklist requirements noted above.
The inspector concluded that:
1)
A check of LTOP operability status was inappropriately omitted from the Mode 6 to 5 checklist.
2)
The SPCG, which is given responsibility for tracking ST intervals for weekly or longer STs, were not tracking LTOPs.
3)
The tracking system used is not conducive to maintaining control over condi tional survei 1 1 ance requi rements.
4) 'rocedure 73AC-9ZZ04, "Surveillance Testing",
inadequately specifies data entry control requirements for starting survei 1 1 ance inter val s.
5)
The Section XI performance group mistakenly believed LTOP operability was not required below Mode 4 and therefore was not tracking LTOP ST due dates.
The inspector noted that because of this, operations was not notified (via the overdue list)
that the LTOP surveillance was going to lapse.
Thus, operations personnel, who have initial interpretation authority over the Technical Specifications applicability, were unable to assess LCO appl icabi 1 ity.
At the end of this report period, and after the fact, the licensee obtained NRC Office of Nuclear Reactor Regulation (NRR) concurrence on an interpretation of the number of days in an 18 month surveillance interval.
This interpretation in effect rendered the LTOP's operable throughout this period.
The inspector considers that the issues raised by this incident still need to be addressed by the licensee.
Licensee management acknowledged these concerns and stated that a
complete programatic review of the ST program had been commissioned to an outside contractor prior to this event and was to be completed shortly.
They indicated that the above concerns would be considered
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during ST program changes following issuance of the contractor's report.
These changes will be reviewed in a future inspection (530/89-36-02).
17.
Fire Protection Evaluation for Trailers Placed Next to the Condensate Stora e Tank (CST)
Unit 3 (71707)
During tours of Unit 3 the inspector observed trailers placed next to the Condensate Storage Tank (CST).
The CST is a safety-related tank and is needed for plant shutdown if the plant is in Modes 1, 2, 3 or 4.
The inspector was concerned that an Appendix R fire protection evaluation should have been performed to ensure that the licensee had adequately reviewed the change in fire loading resulting from placement of the trailer next to the CST.
The licensee produced Engineering Evaluation Request (EER 89-ZY-028 dated June 22, 1989, which addressed this concern.
The EER also states that the trailers should not be installed until the plant had reached Mode 5 or 6 and be removed prior to entering Mode 4.
No violations of NRC requirements or deviations were. identified.
18.
Overfill of Reactor Coolant S stem (RCS) Durin Safet In ection S stem Valve Mani ulations - Unit 3 (93702)
On August 19, 1989, while performing a valve lineup to change Containment Spray Pumps from a shutdown cooling lineup to a
containment spray lineup, RCS level increased from approximately 113 feet 6 inches to 117 feet.
The source of the water was the Refueling Mater Tank (RWT) and the path was provided when the Auxiliary Operator (AO opened the RWT suction valve at the same time the shutdown cooling suction valve was open to the "A" Containment Spray Pump.
The reactor vessel head had been installed and water rose to the lowest opening which was the in-core instrument seal table located in the reactor refueling cavity. Approximately 100 gallons of RCS spilled into the cavity and drained into the reactor cavity sump.
The valve lineup evolution was being controlled by approved procedure 430P-3SI02, Section 6.0.
The sequence of valve manipulations specified by this procedure is correct in that the shutdown cooling suction valve is shut in Step 6.3.4 and the RMT suction valve is opened in Step 6.3.6 thereby preventing a
cross-connect between RMT and RCS systems in which the higher head of the RWT would provide the gravity feed pressure into the RCS.
However, when the valve lineup sheet was given to the AO, he mistakenly assumed it was permissible to operate the valves in a different sequence than was written in the lineup, which would have been correctly sequenced.
Procedure 40AC-90P02,
"Conduct of Shift Operations",
Section 3. 3. 2. 2 states "... strict performance in the order (of steps) written is not required unless specifically stated in the procedure.
The Shift Supervisor/Assistant Shift Supervisor (SS/ASS)
may delay resequence, delete or modify steps...".
Section 3.3.2.2. 1 states
".'..
A step may be resequenced if it is independent of a step which is being delayed...".
The inspector noted that, based on the licensee's report of the incident (memorandum 099-00442-REG),
the AO was tasked
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to perform the valve lineup by an RO and the instructions given to the AO did not include sequence requirements.
Thus the sequence deviation which occurred did not meet the above criteria for a resequence deviation, i.e.
the SS/ASS did not authorize it, and Step 6.3.6 was not independent of Step 6.3.4.
This is an apparent violation of NRC regulations (530/89-36-03).
The licensee's response to this event was to counsel the operators involved, discuss the event with the rest of the operations staff, issue Night Orders stressing the importance of sequence requirement discussions prior to evolutions, and submission of an Instruction Change Request (ICR) to add a "sequence column" to the ODG-17 valve lineup sheets so that valve sequence can be specified.
The inspector concluded that these actions appeared to address the issues raised by this event.
Incor rect Radiation Monitor Alarm Set oint - Unit 3 71707)
On September 2, 1989, during routine setpoint verification checks on the Display and Control Unit (DCU) of the Radiation Monitor System (RMS) in accordance with procedure 75RP-9ZZ89,
"Radiation Monitor Alarm Setpoint Determination",
Radiation Protection (RP) Technicians discovered monitors RU-37 and 38, Containment Power Access Purge Monitors, alarm setpoints at 20 mr/hr (alarm)
and 14 mr/hr (alert).
The expected settings were 2.0 mr/hr (alarm)
and 1.4 mr/hr (alert)
and the Technical Specification maximum setting is 2.5 mr/hr.
The licensee's investigation showed that the monitor alarm settings had not been adjusted since a functional check of the alarm was conducted on August 26, 1989, in preparation for a routine containment purge which commenced at 5:35 p.m.
on that date.
The purge was secured on September 2, 1989, following discovery of the improperly set RMS monitors which were monitoring the purge effluent to atmosphere.
The licensee determined that the functional check per procedure 75RP-9ZZ92,
"Gaseous Radioactive Release Permits and Offsite Dose Assessment",
was not performed properly, in that following a lowering of the alarm and alert setpoints to below the existing reading, such that alarms are verified to occur, the alarm setpoints were not restored to the proper levels.
Two required independent verifications of the proper alarm/alert setpoints failed to detect the error.
Upon discovery, the licensee discontinued the purge and began an investigation which, at the end of this report period, had not been finalized.
However, the two personnel responsible for the performance of the functional test and who were to have verified the alarm/alert setpoints were counseled by management and disciplinary measures were taken.
The licensee reviewed containment air samples taken on August 26 and
'eptember 2, 1989, and plant vent gas, iodine, and particulate monitor readings during this interval, and determined that no undetected release occurre A J
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The inspector considered that the failure to follow procedure 75RP-9ZZ92, which resulted in rendering an operable Technical
,Specification monitor to be inoperable, is a'potential violation of NRC regulations.
However, a final determination will be made when the licensee completes their investigation.
This unresolved item (530/89-36-04) will be turned over to NRC Region V health physics inspectors for follow-up.
TI-15-101 Loss of Deca Heat Removal (Generic Letter 88-17) - Units
2
93 02 This Temporary Inspection Instruction is administratively closed based on the mid-loop operations review in Unit 3, as documented in NRC Inspection Report 530/89-16, paragraph 12.
No violations of NRC requirements or deviations were identified Main Steam Safet Valve MSSV) Blowdown Rin Settin s - Units
2 and
62703 and 93702 On August 31, 1989, the licensee received the results of Unit 3 Main Steam Safety Valve (MSSV) testing from Myle Laboratories.
The test results indicated that "as received" blow down ring settings were outside the specified range for eight of the nine valves tested.
On September 6, 1989, the licensee commenced an orderly shutdown of Unit 2 until a verification of blow down rings settings for the MSSVs at that unit could be completed.
The licensee's engineering personnel have worked closely with Dresser Industries, the valve manufacturer, to locate records of the blow down ring settings for all of the Palo Verde MSSVs.
A review of work orders and valve maintenance was conducted to determine if the ring settings had ever been changed after receipt from the manufacturer.
The valve serialization records and test reports indicate that the blow down ring settings for the Unit 2 valves were verified before shipment to Palo Verde.
A review of Unit 2 maintenance history indicates the ring settings have not been changed since the valves were received at Palo Verde.
The licensee has initiated a maintenance history and serialization record search for the other two units.
The initial review indicates no record of blow down, ring settings'or the Unit 3 valves.
The actions taken by the licensee to this point appear to be conservative.'he inspector will continue to follow the licensee's resolution to the MSSV problem.
Information Notice (IN) 86-05,
"Main Steam Safety Valve Test Failures and Ring Setting Adjustments" was issued on January 31, 1986 and received by the licensee on February 13, 1986.
A Supplement 1 to the IN was issued on October 16, 1986, and received by the licensee on October 23, 1986.
The inspector found the
licensee initially assigned a due date of April 4, 1986, and subsequently changed the due date twice, once to February 26,, 1988, and then to December 30, 1988.
The inspector noted the licensee
'losed out IN 86-05 and Supplement 1 on March 7, 1988.
The closeout did not include any review of ring settings data for the Main Steam Safety Valves.
. The. inspector was concerned with the Nuclear Licensing Department's failure to address IN 86-05 in a timely manner and the failure to review ring setting data when considering the IN closed.
The inspector discussed these concerns with the Vice President of Nuclear Safety and Licensing, who agreed that the time to close the IN was unacceptable and the review should have been more thorough.
The inspector concluded that a proper and timely closure of IN 86-05 and Supplement 1 would have addressed the concern with Unit 3 valves prior to initial licensing of that unit.
22.
Alle ation Followu (RV-89-A-31 a 0 Characterization In June of 1985, a small Loss of Coolant Accident (LOCA)
occurred in Unit 1 while the reactor was operating at power.
Although the event was terminated, its occurrence was covered up by the personnel involved.
b.
Im lied Si nificance to Desi n
Construction or 0 eration Withholding information from the NRC which is required to be reported under
CFR 50.72 or 10 CFR 50.73 is a violation of regulations, as is attempting to suppress, alter, or hide such information.
C.
Assessment of Safet Si nificance The inspector determined that this same concern was reported to the licensee's equality Assurance (gA) Hotline.
The inspector reviewed the licensee's investigation which made the following determinations.
An RCS leak of slightly greater than
gallons per minute occurred over approximately 10 minutes at 12:05 a.m.
on June 28, 1985.
The cause of the leak was incorrect statusing of two pressurizer spray line drain valves which became pressurized following a temporary lift of a clearance associated with the spray valves'he leakage flowed directly into the RDT.
The incident was documented in the Unit Log and Potentially Reportable Occurrence (PRO) report 1-85-195 was initiated to evaluate reportabi lity to the NRC.
The PRO was dispositioned that an LER was not required and the PRO was approved by the Plant Manager and Compliance Supervisor.
The inspector questioned the licensee investigators as to whether they concurred with the disposition on the PRO that an LER was not required and no further action need be taken.
The
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licensee then determined, upon further investigation, that the PRO disposition was appropriat The inspector reviewed the applicable closure memorandum for this gA Hotline file (No. 89-24)
and concluded the investigation was adequate.
d.
Staff Position The allegation was not substantiated.
None.
23.
Review of Licensee Event Re orts Units 1 2 and
90712 92700)
The following LERs were reviewed by the Resident Inspectors.
Based on the information provided in the report, it was concluded'hat reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below listed LERs are considered closed.
Unit 1 LER NUMBER DESCRIPTION 88-23-LO 88-25-LO Broken Bolting in Essential HVAC Dampers (Closed)
Surveillance Test Internal Missed on Cathodic
, Protection System (Closed)
89-04-LO Reactor Trip Due to Control Element Assembly Calculator Failure (Closed)
Unit 2 LER NUMBER DESCRIPTION 88-14-LO Main Steam Safety Valve Setpoints Discovered Out of Tolerance (Closed)
89-01-LO/L1 ESF Actuation Caused by Loss of Power to Class 1E 4160 V Busses (Closed)
89-06-LO/Ll Reactor Protecti on System Actuation Unit 3 LER NUMBER DESCRIPTION 89-04-Ll Engineered Safety Features (ESF) Actuation.
The failure mechanism which caused a spurious Main Steam Isolation System (MSIS) actuation was a high resistance condition across relay contacts that are
required to open to perform their safety function.
Although the event in question occurred because of insufficient current flow due to abnormally high contact resistance, the Licensee Event Report (LER)
had not addressed the root cause of what mechanism was creating the high resistance condition and whether that mechanism could prevent the contacts from opening, thereby preventing fulfillment of its safety function.
The inspector reviewed portions of an analysis performed for the licensee by an independent laboratory (Hi-Rel Reports FR-039382 and FR-088095)
which analyzed the high contact resistance.
These reports conclude that a slight hydrocarbon surface residue is created apparently by the ionization caused by the opening and closing of the contacts with a potential difference.
A scanning electron microscope study shows the residue to be tightly adhering to the contact surface.
No evidence appears to exist, either by analysis, or by fai lure of routine monthly ST's that the contacts would not open when the relay was de-energized (the safety condition).
The inspector concluded that the analysis of the high resistance condition was adequate.
This item is closed.
The following LER's were reviewed but not closed due to having committed to issuing supplemental LER's which had not yet been issued by the end of this report period.
LER TITLE EXPECTED SUPPLE/1ENT ISSUE DATE (as stated on original LER) 528/89-02 Non-gualified Components 07-30-89 Installed on ADV's 528/89-07 Pressurizer Safety 08-31-89 Relief Valve Setpoints Out of Tolerance 530/89-01 Reactor Trip Due to Low 06-30-89 SG Level The inspector further noted that LER 529/89-03 committed to two Human Performance Evaluations (HPES), but subsequently the licensee determined that HPES's would not be required.
The inspector considered that this constituted a substantial change to the originally stated corrective action and should be reported in a supplemental LER.
24.
Review of Periodic and S ecial Re orts - Units 1 2 and 3 (90713)
Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9. 1 and 6.9.2 were reviewed by the inspecto Og r
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 inspector.
Unit 1 o
Monthly Operating Report for July, 1989.
Unit 2 o
Monthly Operating Report for July, 1989.
Unit 3 o
Monthly Operating Report for July, 1989.
No violations of NRC requirements or deviations were identified.
The inspector met with licensee management representatives periodically during the inspection and held an exit meeting on-September 14, 1989.
During the exit meeting, the inspector emphasized the following:
o The fire protection concerns, with the amount of Aqueous Film Forming Foam used on the fire truck and the procedures associated with the foam, the discharge of carbon dioxide during surveillance testing and failure to remove expired flammable storage permits.
o The valve statusing concerns with the Unit 1 spent fuel pool and overfilling the Reactor Coolant System at Unit '3, both of which are potential violations.
o The failure to complete a Transient Review Assessment form prior to restart of Unit 2 after the July 12, 1989 trip.
C o
The failure to perform a timely and thorough review of Information Notice 86-05.
o The failure to meet commitment dates for supplemental LERs.