IR 05000528/1989021
| ML17304B386 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 07/26/1989 |
| From: | Richards S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17304B385 | List: |
| References | |
| 50-528-89-21, 50-529-89-21, 50-530-89-21, NUDOCS 8908160251 | |
| Download: ML17304B386 (36) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION REGION V
Re ort Nos.
Docket Nos.
License Nos.
Licersee:
Facilit Name:
50-528/89-21, 50-529/89-21 and 50-530/89-21 50-528,- 50-529, 50-530 NPF-41, NPF-51, NPF-74 Arizona Nuclear Power Project P. 0.
Box 52034 Phoenix, AZ. 85072-2034 Palo Verde Nuclear Generating Station Units 1,
& 3 Ins ection Conducted:
April 27 through June 11, 1989.
Inspectors:
T. Polich, Senior Resident Inspector D. Coe, Resident Inspector Y. f1iller, Regional Inspector J, Ball, NRR N. Davis, NRR T. Foley, NRR Approved By:
S. Pichards, Chief Reactor ProjectsSection II 7-26-89 Date Signed Ins ection Summar
Ins ection on A ri 1 27 throuqh June 11, 1989.
(Report Nos.
50-528/89-21, 50"529 89-2)
and 50-530/8
"21 Areas Ins ected:
Routine, onsite, regular and backshift inspection by the two resi ent inspectors, one Region V inspector, and three NRR inspectors.
Areas inspected included: previously identified items; review of plant activities; engineered safety feature system walkdowns; monthly surveillance testing; monthly plant maintenance; preventative maintenance program - Units 1, 2, and 3; restart review - Unit 2; steam generator tube plug concern - Unit 2; loss of spent fuel pool level-Unit 3; auxiliary feedwater flow control valve found installed backwards
- Unit 3; inoperable potter - brumfield relays - Unit 3; and review of periodic and special reports - Units 1, 2 and 3.
During this inspection the following Inspection Procedures were utilized:
30702, 30703, 60705, 61726, 62703, 71707, 71710, 92700, 92701, and 93702.
8qpg g 6025 ~
5ppp 528 Sep72~
pDR ADOCH. p pgU
Safet Issues Mana ement S stem (SIMS) Items:
None Results:
Of the Nine areas inspected, no violations were identified.
General Conclusions and S ecific Findin s
Si nificant Safet Matters:
Hone Summar of Violations:
None
.
Summar
~ nf Deviations:
None 0 en Items Summar
3 new items opene DETAILS Persons Contacted The below listed technical and supervisory personnel were among those contacted:
Arizona nuclear Power Project (ANPP
- R. Adney, J. Allen, J. Bailey, B. Ballard, Sr.
P. Brandjes, C. Churchman, W. Conway,
- J. Haynes,
- D. Heinicke,
- P. Hughes,
- W. Ide,
- D. Karner, J. Kirby, J. LoCicero,
- W. Marsh, A. NcCabe,
- L. Papworth, D. Phillips, J. Reilly, A. Rogers,
- C. Russo, T. Shriver, G. Sowers, R. Younger, W. guinn, Plant Manager, Unit 3 Relief Plant Manager Assistant Plant Manager, Unit 3 guality Assurance Director Central Maintenance Manager Work Control Manager, Unit 3 Executive Vice President.
- Nuclear Vice President, Nuclear Production/Site Director Plant Manager, Unit 2 Radiation Protection 5 Chemistry Manager Plant Manager, Unit 1 Vice President - Nuclear Director, Nuclear Production Support Independent Safety Engineering Manager Plant Director Maintenance Manager, Unit
Site Services Director Outage Management Manager Standards and Technical Support Director Licensing Manager Assistant (}uality Assurance Director Compliance Manager Engineering Evaluations t~ianager Plant Standards and Control Manager Nuclear Safety and Licensing Director 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 June 27, 1989.
Review of Plant Activities (71707, 71710, 93702)
a.
Unit
Unit 1 began this inspection in Mode 5, at day 20 of it'
second refueling outage.
On Nay 12, 1989, the reactor vessel head was detensioned and Node 6 (refueling)
was entere b.
Unit 2 Unit 2 remained in Mode 5 for the entire inspection report period, primarily to replace the Atmospheric Dump Valves with modified versions, and to complete modifications to emergency lighting systems.
The integrity of some of the steam generator tube plugs was questioned during this period (see paragraph 8.)
c.'nit
Unit 3 remained in a core off loaded condition throughout the entire inspection report period.
Outage related work continued on Potter-Brumfield relay replacement (see paragraph 11),
Reactor Coolant Pump internals inspection, and steam generator eddy current testing.
d.
Plant Tours The following plant areas at Units 1, 2 and 3 were toured by the inspectors during 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 eratinq Lo s and Records Records were reviewed against Tec nica Speci ication and administrative control procedure reouirements.
2.
Monitorina Instrumentation Process instruments were o serve or corre ation etween channels and for conformance with Technical Specification requirements.
S~ti<<
i
6 lif ig observed for conformance with 10 CFR 50.54.(k), Technical Specifications, and administrative procedures.
4.
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.
5.
E ui ment Ta qinq Selected equipment, for which tagging requests had been initiated, were observed to verify that
tags were in place and the equipment was in the condition specified.
6.
General Plant E ui ment Conditions Plant equipment was o serve or
>n scations o
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 hi 1Sp if'.
i
administrative procedures.
8. ~Ch i<<Ch for conformance with Technical Specifications and admin-istrative control procedures.
g.
Securitv Activities observed for conformance with regulatory requirements, implementa'.ion of the site security plan, and administrative procedures including vehicle and personnel access, and protected and vital area integrity.
10.
Plant Housekee in 'lant 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.
11.
Radiation Protection Controls Areas observed included contro 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.
Ho violatinns of NRC requirements or deviations were idertified.
3.
En ineered Safety Feature S stem Malkdowns - 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
o Fuel Building Essential Yentilation, Train "A"
"A" Control Room Essential Ventilation, Train "8" DC Batteries
"A" and
"C" Unit 2 Unit 3 DC Batteries
"A", "B", "C" and
"D" No o
Fuel Building Essential Ventilation, Train "A" violations of NRC requirements or deviations were identified.
4.
Monthl Surveillance Testinq - Units 1, 2 and 3 (61726)
a
~
b.
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 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.
Specifically, portions of the following surveillances were observed by the inspector during this inspection period:
Unit
Procedure Descri tion o 72ST-1RK09 Shutdown Margin Unit 2 No d>>
o 36ST-9SQ04 RMS Functional violations of NRC requirements or deviations were identified.
5.
Monthl Plant Maintenance - Units 1, 2 and 3 (62703)
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 proce'dures, required Quality Assurance/Quality Control (QA/QC) 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 correc b.
Specifically, the inspector witnessed portions of the following maintenance activities:
Unit
Descri tion o
Refurbish/Reinstall 13.8 KV Bus Bar Elements o
Tear Down/Inspect Emergency Diesel Generator
"B" o
Clean/Vacuum Turbine Building 480 V Breakers Unit 2 Descri tion o
"Atmospheric Dump Valves Disassembly, Examination and Reassembly".
Unit 3 Descri tion o
Reassemble FWIV 4-Way Valves o
Reassemble FWIV 4-Way Accumulators o
"Snubber Installation" No violations of NPC requirements or deviations were identified.
6.
Preventative Yiaintenance (PYi) Proqram - Units 1, 2, and 3 (62700)
The inspector investigated the maintenance history of the Unit
NAN-S02 13.8 KY normal feeder breaker (1E-NAN-S02A), which failed to fast trans er during the Unit 1 reactor trip of triarch 5, 1989.
The fai lure of this normal feeder breaker
.o trip resulted in the loss of power to two reactor coolant pumps (RCPs).
Additionally, a fire was observed and subsequently extinguished on the trip coil of 1F.-MAN-S02A.
A fast bus transfer signal was initiated following the main generator trip.
NAN-S01 was successful in fast transferring to the startup transformer, re-energizing from NAN-S03.
NAN-S02 was not re-energized from NAN-S04 because of the failure of breaker 1E-NAN-S02A to trip.
The most probable cause for this failure was a
slight lateral misalignment (cocking) of the trip armature combined with a possible lubrication degradation in components actuated by the trip armature.
The trip armature begins to move when the trip coil is energized and travels between one-sixteenth to three-sixteenths o
an inch, rotating the trip latch off the trip latch roller, permitting the operating mechanism linkage to collapse, and the openinq springs to interrupt the circuit.
The lateral misalignment of the trip armature was noticed hv engineering personnel during investigatior into the breaker malfunction.
When the trip coi 1 u:as energized, the
lateral misalignment, possibly combined with friction from degraded lubrication on associated components, may have prevented the trip armature from traveling far enough to fully rotate the trip latch.
The trip coil therefore remained energized, overheated, and caught fire.
The vendor technical manual (GK-7347C) for this type circuit breaker recommends that all breakers be operated at regular intervals, at least once a year, to ensure the lubrication is in good condition and the breaker is operable.
quarterly periodic maintenance task No. 051488 that exercises breaker lE-NAN-S02A had been waived for three consecutive quarters and was last performed on February 2, 1988, approximately 13 months before the Unit 1 event.
The reason for waiver of the breaker exercise task was that operations would not allow equipment to be taken out of service due to existing plant conditions.
The process for waiving PYi tasks was not adeouate to ensure that PMs were performed as required when plant conditions were favorable.
The licensee is revising procedures for approval of PM waivers.
Figure 17 in the vendor technical manual (GK-7347C) gives a
recommended lubrication chart and is divided into two methods of lubrication.
The first method outlines lubrication activities recommended to be performed at the time of periodic maintenance, and does not require disassembly of the breaker.
The second method
=-
specifies alternate lubrication activities that require breaker disassembly, and is performed when a general overhaul of the breaker is conducted.
The Engineering Evaluation Department (EED) has recommended to the Plant Standards Electrical Department that both lubrication schedules be implemented.
Yiaintenance procedures 32MT-9ZZ29, "Maintenance of Medium Voltage Circuit Breakers" and 32ST-9ZZ06,
"60 Month Containment. Penetration Conductor 13.8 KV Breaker Inspection, Testing and PM." required only the first method lubrication at maintenance periods.
The recommendation made by the EED called for implementation of the section titled "Lubrication at Maintenance Period,"
each refueling outage and f'r the Alternate Lubrication" method every third refueling outage.
The vendor technical manual (GK-7347C)
recommends measuring the pick-up voltage for the trip coil,at least once per year.
This was not a
PM requirement prior to the Unit 1 breaker failure.
The periodic maintenance procedure for these breakers was rewritten.
Procedure 32MT-9ZZ33, "Maintenance of Medium Voltage Circuit Breakers Type AM-13.8-1000," was issued on April 29, 1989',
and
.
requires verification of the trip coi 1 and spring release coi 1 minimum pick-up voltages and also requires that a copy of the results be forwarded to the Engineering Evaluation Department responsible System Engineer.
On May 8, 1989, the inspectors toured the Unit 2 Auxiliary Building, Radwaste Building and Fuel Building with the lead Radiation Protection Technician.
No deficiencies were note The inspectors witnessed portions of the reassembly work on the Unit 2 Atmospheric Dump Valve ADV-185, in accordance with 31MT-9SG04,
"Atmospheric Dump Valves Disassembly, Examination and Reassembly".
The inspectors observed installation of the ADV-185 seating ring spacer, seating ring gaskets, seat ring, disc stack, and plug assembly during valve reassembly on Nay 9, 1989.
No deficiencies were noted.
'I On Hay 11, 1989, the inspector witnessed portions of the reassembly of instrument air lines on ADV-185 in Unit 2 in accordance with Work Order,No.
00356387 and 31NT-9SG04.
No deficiencies were noted.
No violations of NRC requirements or deviations were identified.
7.
Restart Review - Unit 2 (92700
.
On Nay 26, 1986, the licensee issued the Unit 2 "Restart List" and in a letter dated the same day transmitted the list to Region V.
As part o
the NRC review of the Unit 2 restart, items were selected from the restart list to be reviewed by the resident, regional, and headquarters based inspectors.
The inspectors reviev~ed 102 items, which represented approximately 53 percent of the restart list items.
The inspectors have reviewed these items and found them to be acceptable.
However, during the review of these items several problems were noted and were subsequently resolved to the inspectors'atisfaction.
The following items were the most significant.
Preventive Maintenance
{PMs).
Durino review of Preventive Yaintenance (PNs) licensee record No. 112, which were waived or incomplete prior to Unit 2 restart, the inspector questioned why Plis on the Diesel Generator (DG) excess flow check valves (XCV's) associated w'ith air starting pressure indicator PI-30 were not completed due to
"lack of material".
The inspector determined that the PYi had, in fact, been completed and the licensee removed it from the list of waived PNs.
The inspector also determined the following:
1)
XCV's are designed to close under excess flow conditions associated with a break of non-seismic piping downstream of the valve.
2)
The PN task was initiated in response to EER 86-XH-046, which raised the concern that safety system (DG and others) operability would be in question following a Safe Shutdown Earthquake (SSE) in which the non-seismic piping ruptured and the XCV stuck full open.
3)
The EER referenced a calculation (13-NC-ZZ-704) which, in summary, stated that even if the DG XCV stuck full open,
CE L1
that the" resulting flow rate and air loss would not.he sufficient to remove the five-start des'ign capability within about the first 30 minutes.
Based on this conclusion, alarm response procedure 41AL-1RK7C, Window 7C14A (Seismic Occurrence),
requires that,'following an SSE, an operator is to immediately (within 30 minutes)
shut the XCV isolation valves for the DG (and several other) safety systems.
4)
The actual calculation 13-MC-ZZ-704 (not the summary) for the DG system, shows that the DG loses all start capability within 30 minutes if both XCVs stick full open.
The inspector questioned the adequacy. of the procedures and the calculation to reliably ensure the operability of the DG following an SSE.
The licensee responded by shutting the XCV isolation valves on affected safetv systems, unless taking instrumen
. readings on gauges isolated by th'.s action, until a
satisfactory long term resolution can be achieved.
The inspector concluded that the licensee's response was-conservative.
However, the adequacy of the licensee's previous engineering analysis and resolution of seismic concerns associated with XCVs will require further investigation which is planned by the licensee.
Although the restart concern is resolved, the previous enoineering analysis will be followed up in a future inspection (Unresolved Item 50-529/89-21-01).
b.
Two 0 eratin Procedures for the Manual 0 eration of Steam B - ass Contro S stem SBCS
.
Licensee records No.
94 and Ho.
756 are restart items which describe changes to two separate plant procedures.
Both include procedures for manually operating the SBCS valves.
Parts of these procedures cover the same operation.
The procedure numbers are 420P-2SF05 and 42DP-20P01.
The inconsistencies found are as follows; 1)
The SBCS section of the OP procedure does not have
sign-offs at each procedure step, although sign offs at each step are included in the DP procedure and in the other parts of the OP procedure.
2)
The sequences for valve operation are not identical between the two procedures.
3)
The OP procedure refers to Appendix D for isolation of the SBCS valves, however Appendix D is a listing of the isolation valves without any accompanying instructions.
4)
The DP procedure contains instructions for the operation of valves from the control room to support the steps required for manual operation, as well as the manual valve
operation steps.
The OP procedure contains only loca'i manual valve operation to be accomplished in the Auxiliary Buildino.
These findings were discussed with the Compliance Manager, the Director of Standards and Technical Support, and the Unit 2 Plant Manager.
In addition, the inspector discussed the fact that these inconsistent procedures went thorough the required licensee review process and were issued within 8 weeks of each other.
This indicated a weakness in the overall review of plant procedures.
The licensee stated that the following actions would be taken; I)
For the manual operation of valves, the licensee is already following a program to ensure that only one procedure for an operation will be in use.
The duplicate procedures occurred because the procedure writing group was not required to follow through and immediately delete duplicate procedures where restart work was concerned.
2)
The listing of isolation valves instead of clear procedures for isolating SBCS valves will be revised to include clear instructions for the isolation of the valves.
Licensee Record No. 80, Li htin Preventive Maintenance.
Concern Reqardina Communication Inade uacies Between the
)
Control Room and
,uxi waar erators Corrective ction 5.25 of Issue No. 5.
The procedures for light bulb replacement which the licensee submitted for review have no verification step to ensure that the reauired illumination has been obtained.
Also, the PM does not require the illumination to be verified at night for those areas affected hy daylight.
The inspector discussed these issues with the Director of Standards and Technical Support, who agreed to address these issues in the procedures.
A detailed review was conducted of the auxiliary operators'ommunication devices and the capabilities of these devices.
Discussions were held with the Control Room Supervisors, Operators and Auxiliary Operators of Units I, 2, and 3, plus with technical personnel cognizant of communication at the faci 1 ity.
Responding to this concern the licensee issued a memorandum 260-00071-WCM dated May 1, 1989, requiring Auxiliary Operators (AOs) to be issued a tool belt including a radi o and a Radio Shack hand walkie-talkie ear plug.
Additionally, operations was required to evaluate the use of vibrating pagers for contacting ROs in high noise areas.
Another memorandum from the Unit " Operations Yianager to the Compliance Yianager on
June 8, 1989, required operators to use head sets in high noise areas until another alternative method is chosen.
Currently, the licensee's primary means of communication, in accordance with the FSAR, is the telephone.
Other communicating devices are the plant page and the radio/walkie-talkie.
Recently a vibrating pager has been added for evaluation for alerting the AOs to contact the control room.
The primary means of communication for the AOs with the control room has been and remains the radio/walkie-talkie with a microphone attached.
The microphone is normally attached to the AOs upper shirt.
The short comings of this device are:
1)
There are no preventive maintenance (PN) measures associated with maintaining the radios or the microphones.
At Unit 2, five General Electric (GE) radios exist with only one GE microphone for all three units.
Some radios work better than others.
They are ail old and worn.
2)
Radio reception is weak and garbled in some locations within the plant (i.e. inside the Biological Shield Wall in Containment, the lower levels of the Auxiliary Building, and in the RF shadow behind the Containment Structure).
3)
The Auxiliary Operators (AOs) at all three units indicated that the carrying of a radio is cumbersome, and that the wire between the radio and microphone gets cauqht on components.
The devices routinely suffice as a means of communication.
Yiost often AO's cannot communicate between each other unless under ideal conditions ( line of sight without interference).
The device is acceptable under routine conditions because AOs can work around it's inadeouacies.
AOs can move to a
location where the device is better suited.
However, during times where full attention is reouired to support another activity, under emergency conditions such as fighting a fire, under wet conditions or in a high noise area, or if the radio is not attached to their body when maneuvering in tight spaces, operators at times are not alerted to the radio call or can't hear transmissions.
Radios have also become wet and short circuited, thus becoming inoperable.
In response to these concerns, licensee management has issued a
variety of ear plug microphones to Unit 2 operators.
The operators interviewed did not like these devices, stating that; 1)
One could not clearly hear communications 2)
The plug hurt their ears J
3)
The wire to the radio caught on more obstacles than the previous pre-coiled wire to the microphone Additionally, the Operations department issued a directive for AOs to wear ear muff type headsets attached to the radio while in high noise areas.
These are much larger and provide good quality communications, however they are cumbersome, hot and the AOs cannot hear other sounds.
There are only four sets currently in the AOs office adjacent to the Control Room.
Operators are unlikely to return to the AO office to put on a
pair of headsets to enter a high noise area that is immediately close by the AO's work position, i.e.'the outside AO is unlikely to return to the Control room to get a special headset to enter the diesel generator room.
The licensee is currently upgrading the existing radio system by improving the pre-amplifiers to the four Radio Frequency (RF) transmitters and installing a
VOTOR system.
These will enhance the communications to the Control room from the field.
They will not. enhance communications to the AOs or between the AOs.
In Sumarv The Communication ability at Palo Verde is strained.
Operators make due with an outdated system which provides marginally adequate communications during routine opera.ions, but becomes inadequate under severe conditions.
The current enhancement (vibrator pager),
aids in alerting the AO to his being paged, but does nothing to enhance communications.
Communications engineers and knowledgeable AOs both suggest the installation of additional antenna in the RF weak areas of the plant, and the installation of one or two repeaters per unit in lieu of additional RF transmitters.
This would enhance communications between both the AO and the Control Room and between AOs and other AOs.
Additionally the licensee should consider instituting a Preventive Maintenance (PM) program for their existing communications equipment and ensure that sufficient and well performing radios and microphones are available for AOs.
The current system design does not fit the need of Auxiliary Operators.
Even with the currently planned actions and AO recommended suggestions implemented, communication difficulties would appear likely under strained conditions such as fire fighting, or working in loud noise areas such as in the Emergency Oiesel Generator or MSIV rooms.
Not withstanding the installation of a new system, issuance of vibrating pagers appears to be a sufficient temporary solution for obtaining the AO's attentio Review of Licensee's Corrective Actions for Deficiencies in mer enc an ssentsa
>
tsnq.
The inspector reviewed measures taken by the licensee to confirm that adequate lighting exists in all areas of the plant, to perform required tasks, as a result of findings from a
NRC Region V Augmented Inspection Team (AIT) investigation of the March 3, 1989, trip of Palo Verde Unit 3.
The AIT determined that emergency lighting for the main steam support structure failed during the event, hampering the operators in their attempt to cope with the atmospheric dump valve (ADV)
failure.
During this inspection, the inspector reviewed walkdown results of Unit 2 and the drawing review conducted by the licensee.
From this, the inspector ascertained that the licensee had determined there were areas where emeroency lighting was needed to perform a potentially safe shutdown activity, but that did not currently exist.
The inspector performed an independent walkdown of selected areas in Unit 2.
This was done with representatives of the licensee's engineering staff and an auxiliary operator.
The inspector referred to licensee procedure No. 42A0-2ZZ44, Revision 1, "Shutdown Outside the Control Room Due to Fire and/or Smoke" for identi ication of pctentially safe shutdown activities.
During this walkdown, the inspector made the following observations:
On the 120 foot elevation of the auxiliary building in the North corridor at auxiliary relay panel 2E-ZAN-C02, emergency lighting was located on the opposite side of the panel doors required to be opened to gain access to disconnect switch 16-10, which by procedure must be opened to insure a spurious signal does not open valve, CH-PDV-240, causing a loss of auxiliary spray flow.
This discrepancy haC not heen previouslv identified by the licensee.
Emergency lighting fixtures within the "B" diesel generator room did not appear to be optimally located so as to permit the confirmation of six of twelve prerequisites for manual start of the diesel generator from a standby condition, as outlined in Appendix B of procedure No. 420P-2DG02, Revision 7, even though 42AO-2ZZ44 does permit the exclusion of the prerequisite section of 420P-2DC02 at the discretion of the shift supervisor.
In addition, the inspector questioned the ability of the licensee's operators to affect a manual reset of the diesel generator engine should an initial start attempt be unsuccessful.
Emergency lighting fixtures within the "B" auxiliary feedwater pump room also did not appear tn be optimally positioned so as to permit local-manual control of auxiliary feedwater isolation valves, AFB-UV-34, 35, or auxiliary feedwater regulation
tl
valves, AFB-HV-30, 31, even though these valves would normally be able to be controlled remotely using hand switches, AFB-HS-34B, 35B, and AFB-HS-308, 31B, located on remote shutdown panel E01, Train "B".
However, inability of the operators to take control of the ADVs either from the control room or remote shutdown panel durinq the March 3 event caused the operators
=to have to attempt to take local-manual control of the ADVs.
The inspector also observed a number of areas where light bulbs needed to be replaced'n one room in particular, five of six normal lighting fixtures had burned out light bulbs.
A light bulb was also found to be burned out in an essential lighting fixture along the ingress/egress route to the auxiliary feedwater pump rooms.
From these observations, the inspector judged that the licensee's defined corrective actions for deficiencies in emergency and essential lighting were incomplete and limited in both scope and depth.
The licensee's actions to date appeared to the inspector to be more compliance oriented than geared to assuring operational safety.
The licensee informed the inspector that a maior project was planned which would perform a comprehensive review of all lighting emergency (essential and normal).
Details of this project, however, were not presented.
The inspector felt that at present the project appeared to lack well defined intermediate goals or objectives or the establishment of milestones which could assure the realization of the licensee's stated intention of completing their review and implementing changes hy July, 1991.
Review of Ade uac of Trainin and Procedures for Local-Manual 0 eration of Plant Equi ment.
As a result of the March 3, 1989, Unit 3 trip in which operators encoun
.ered difficulties with local-manual operation of atmospheric dump valves (ADVs), a concern over the adequacy o-, trainino and procedures for local-manual operation of plant equipment developed.
During this inspection, the inspector reviewed work done by the licensee to address concerns of training on infrequent and important to safety tasks for licensed operators, non-licensed operators, and emeroency plan positions.
The licensee was found to have secured analyst support from General Physics for the review of task lists and training materials for both oualified licensed and non-licensed operators.
From this review, the licensee; in concert with their consultants, identified three tasks each for licensed and non-licensed operators in need of immediate training.
They were for licensed operators:
manual operation of atmospheric dump valves, directing the reset of the auxiliary.eedwater pump
Wl
terry turbine driver overspeed trip device, and manual initiation of engineered safety features; and for non-licensed operators:
manual operation of atmospheric dump valves, manual operation of main steam isolat'.on bypass valves and tripping and resetting of the auxiliary feedwater pump terry turbine driver overspeed trip device.
In addition, the licensee's consultants recommended that all plant systems be reviewed to determine if other remote or automatically operated valves with local-manual operation capability need to be added to both the licensed and non-licensed operator task lists.
At the time of this inspection, the inspector determined that licensee management appeared not to have taken a definitive position with regard to this recommendation and thus no actions appeared to be underway to address this potential concern.
In addition, the inspector reviewed the licensee's overall plan to replace the Operations Department Guideline, ODG-30, with unit specific Departmental Procedure 4iDP-10FOl, 42DP-20F01, and 43DP-300FOi,
"t>manual Operation of Air Operated Valves".
At the time of this inspection, enhanced procedures providing instructions for four groups of valves had been completed.
They are the atmospheric dump valves (ADVs), main steam isolation valves (NSIY), bypass valves, feedwater downcomer containment isolation valves, and the steam bypass control system (SBCS) valves.
The licensee's future plans were found to include incorporation of groups o: valves with the same type of details and enhancements into the new procedures in an order identified by operations and the eventual cancellation of ODG-30.
The licensee was however, unable to provide the inspector with a detailed plan or specific milestones which had been identified for the completion of this proiect.
The licensee merely forecast that the project would take several months due to the number of valves involved and due tn the time necessary to accurately research the information required to provide morc detailed and enhanced instructions.
The licensee's decision as to whether or not to include specific traininq on other remote or automatically operated valves with local-manual operation capability in the licensed and non-licensed operator task lists, and the time table for providing enhanced instructions for all valves included in ODG-30, is considered an open item (529/89-21-02).
Review of Ade uacy o
Labelin of Com onents Re uired for Nanua eration o
tmos eric um Va ves.
As a result of the Parch 3, 1989, Unit 3 trip in which operators encountered difficulties with local-manual operation of atmospher'.c dump valves (ADVs), a concern developed over the adequacy of labeling of components required for local-manual operation of the ADVs.
During this inspection, the inspector verified in Unit 2 that the licensee had improved the labeling of various valves within
the instrument air system and back-up nitrogen system, which are manipulated during the course of local-manual operation of the ADVs.
The inspector also verified both the installation of placards and the painting of an arrow on the hand wheel of each ADV indicating the direction of rotation for opening of the valves.
The actions taken by the licensee appeared sufficient to alleviate the concern over adequacy of labeling.
h.
Review of Procedures and Trainin for Resettinq of Protective
~Re a s.
On March 5, 1989, a trip of Palo Verde Unit 1 occurred due to a Control Element Assembly Calculator (CEAC) failure.
The fast bus transfer was unsuccessful for 13.8 KV bus NAN-S02 because the normal feeder breaker did not'trip as required.
During the re-energizing of NAN-S02, damage occurred to the RCP 1B and 2B 286 relay trip coils.
The failure of the RCP 286 relay coils was attributed by the licensee to inadequate procedural guidance, training, and the uniqueness of the RCP trip circuit design.
During this inspection, the inspector reviewed a copy of'rocedure No.
"Relay Resetting,"
which is intended to provide improved procedural guidance for resetting of protective relavs.
This review determined that once implemented, this procedure along with its incorporation by reference into related procedures such as, 42A0-2ZZ12, Revision 1,
"Degraded Electrical Power", should alleviate the concern over lack of'dequate procedural guidance in this area.
8.
Steam Generator Tube Plu Concern
- Unit 2 (62703).
On May 15, 1989, Nuclear Regulatory Commission Bulletin 89-01,
"Failure of Westinghouse Steam Generator Tube Mechanical Plugs,"
was issued.
Palo Verde Unit 2 has Vestinghouse mechanical plugs of heat number 4523 installed in both the hot and cold legs of the No.
1 and No.
The licensee responded to Bulletin 89-01 on June 2, 1989, and stated they decided to operate Unit 2 until the end of Cycle 2.
The fuel cycle will allow operation of Unit 2 to exceed the calculated steam generator mechanical plug life of the
hot leg plugs by 34 effective full power days.
The licensee has discussed this response with the NRC Office of Nuclear Reactor Regulation.
The issue will be followed up as part of the bulletin close out in a future inspection.
9.
Loss of S ent Fuel. Pool Level - Unit 3 (92700)
On May 22, 1989, at approximately 4:25 a.m., Unit 3 personnel were recirculating the Spent Fuel Pool (SFP)
through the B cleanup ion exchanger to boron sa urate the newly installed resin.
Operators noticed the SFP level decreasing and stopped the cleanup pum Concurrently, they noticed a rise in the refueling canal level, which was lower than the SFP.
The level drop continued for 9.5 inches until operators identified an inadvertent flow path which allowed a gravity drain from the SFP to the canal.
One of the valves in this flow path was open when the control room status prints showed it to be closed.
When the SFP level drop was stopped, level was approximately two feet above the Technical Specification minimum level for spent fuel stored in the pool.
The licensee's investigation of this event indicated that the mispositioned valve was opened on May 15, 1989, as part of a routine system realignment.
The licensee was unable to positively confirm the reason the control room status prints were inaccurate.
The inspector observed that the controlling procedure, 4XOP-XPC01, Revision 0, "Fuel Pool Cooling and Cleanup" did not require restoration of valve lineups to a
"normal" lineup between specific evolutions and alterations to the system.
This increases the risk of improper valve lineups.
The licensee's procedure System Status Control, ODG-17, requires that system valve status be accurately represented on control room status prints.
Operations Technicians update the prints followino completion of lineups.
The inspector observed that the requirements of this procedure were apparently not followed in that one valve was physically opened on May 15, 1989, and was so documented on a valve lineup sheet, but was shown as closed on the status prints on May 22, 1989.
There. were no valve lineup sheets retained which showed any further valve repositioning of this particular valve.
The inspector concluded that procedure 410P-1PC01 was lax in controlling system status and that ODG-17 requirements were not adhered to during system realignments.
The licensee restored the Spent Fuel Pool system tn its "normal" configuration and established a policy among all three units that the "normal" lineup would be restored folios(ing completion of each system evolution.
In addition, adherence to ODB-17 was emphasized.
An Instruction Change Request was initiated by Unit 3 for 4XOP-XPC01, to provide better system control and more easily understood direct'.ons.
The inspector concluded that the licensee's immediate responses were adequate for this instance, but that the licensee should review their system status control requirements from a broad perspective.
Licensee representatives indicated this will be done.
This item will remain open until the review is completed (530/89-21-01).
No violations of NRC requirements or deviations were identified.
Auxiliar Feedwater Flow Control Valve Found Installed Backwards-Unit 3 93702 On May 11, 1989, the licensee discovered that one out of four AFH flow control valves in Unit 3 was installed in reverse orientation from that specified by the vendor print.
This condition was discovered when the valve was disassembled for corrective
maintenance on a bonnet leak.
The licensee verified the correct orientation of all other AFW flow control valves on site, including Units I and 2, using a ultrasonic test device to examine valve intervals.
A flow direction arrow was riveted to the valve body and was consistent with actual flow direction through the valve, but was incorrect according to the vendor print.
The valve is a self-drag velocity control element valve manufactured by Control Components Inc. (CCI) and is similar to the Atmospheric Dump Valves (ADVs)
being modified following the March 3, Unit 3 trip.
Although the licensee determined that all other AFM flow control valves were oriented properly, three valves in Unit 2 had no valve ID plate riveted to the valve outlet as per the vendor print, and the three correctly oriented valves in Unit 3 had the valve ID plate riveted to the valve inlet.
The reversed valve, 3JAFB-HV-31, had the ID plate riveted 'to the valve outlet, but since the "valve was reversed, the ID plate was consistent with the other Unit 3 valves in that it was oriented on the side of the valve into which actual flow was admitted.
The orientation of the valve is significant from a long term operability perspective.
The valve has functioned adeouately since it was installed, but had experienced some slight scoring on the seat pluo due to foreign particles entrained in the flow becoming trapped in the labyrinth disk stack which surrounds the seat plug and, depending on plug position, controls the amount of flow.
Over time, this scoring could allow increased leakage flow when the valve was shut.
The licensee determined that flow and ID tags were installed during valve manufacture and issued work requests to replace missing tags and reinstall incorrectly placed taqs.
In addition, the reverse oriented valve will be cut out and reinstalled in its correct orientation.
The inspector concluded that the licensee's actions appeared adequate.
Ho Yiolatiors or deviations of NRC requirements were identified.
Ino erable Potter-Brumfield Rela s - Unit 3 (61726, 62703, 92700).
On April 25, 1989, Unit 3 was undergoing a refueling outage and replacement of all Potter-Brumfield safety-related relays were nearly complete.
These relays were being replaced as a long term corrective action to address a history of relay failures due to contaminants within the relay's motor chamber, which in some cases prevented full rotor movement and contact makeup.
However, on this date, the first 44 newly installed relays were individually tested and 10 were discovered to either fai 1 to move or did so sluggishly when power was removed (the safety activated condition).
Two management level vendor representatives arrived on-site later that day and observed te:ting which repeated this phenomena.
They took five of the relays for further evaluation.
The licensee also called
in a second party independent laboratory to perform an assessment of the problem.
Relay model numbers affected were No. 7061, 7062, and No. 7063.
The original problem was reported by LER 88-18.
The licensee and vendor identified the problem to be due to a
cementing of the rotor and stator portions of the relay drive motor.
The cementing effect was due to the use of a new epoxy coating on the two coils used in the drive motor, which had inadvertently deposited on rotor/stator mating surfaces.
The coil coating had been changed to prevent an off-gassing of the previously used varnish coating which had caused gummy deposits to interfere with relay operation.
The problem identified with the modified relays is unrelated to this original problem.
The licensee issued a Part
report on Nay 8, 1989, to document this new problem.
The licensee began replacina the newly installed relays with modified relays that
'ad been disassembled hy the vendor and had been checked for evidence of epoxy on areas other than the coils.
On Nay 8, 1989, the vendor notified the licensee that the epoxy on some of the relays had been found not completely cured and was potentially transportable to other areas of the drive motor following a satisfactory initial inspection.
The licensee halted further relay replacement.
Based on this concern, the vendor modified its manufacturing process to apply and cure the epoxy onto the coils before the coils were mounted onto the stator.
Furthermore, the vendor committed to improved quality controls on the handling and storage of the epoxy resin.
Relays manufactured in this manner were received from the vendor in early June, 1989 and the licensee began installing them in the place of the previously modified and un-modified relays.
The inspector concluded that the licensee's response to the self-revealing events appeared adeauate, however further review of the licensee's procurement process for dedicating commercial grade electrical components to safety grade status should be completed.
The licensee's root cause of failure analysis will be reviewed as part of closing LER 89-007 and its supplement's.
No violations or deviations of NRC requirements were identified.
Review of Periodic and S ecial Re orts - Units 1, 2 and 3.
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
o Monthly Operating Report for April and Nay, 1989.
Unit 2 o
Monthly Operating Report for April and May, 1989.
Unit 3 o
Monthly Operating Report for April and May, 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 June 27, 1989.
During the exit meeting, the inspector emphasized the following:
o The excess flow check valve resolution appears appropriate.
However, the engineering analvsis is in question and will be followed up in a future inspection (see section 7.a)
o Communications in high noise areas are marginal,and further enhancements to the licensee's communication system is strongly urged (see section 7.d).
o Licensee management needs to address the method of control of status prints to prevent misinformation and improper valve lineups (see section 9).
't The licensee acknowledged the inspectors concerns and acknowledged the commitments that the inspectors noted in the other sections of this report.