IR 05000528/1987001
| ML17303A347 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 03/13/1987 |
| From: | Ball J, Bosted C, Fiorelli G, Ivey K, Richards S, Zimmerman R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17303A346 | List: |
| References | |
| 50-528-87-01, 50-528-87-1, 50-529-87-01, 50-529-87-1, 50-530-87-02, 50-530-87-2, GL-85-05, GL-85-5, IEB-85-001, IEB-85-1, IEIN-85-045, IEIN-85-45, NUDOCS 8703300575 | |
| Download: ML17303A347 (50) | |
Text
U. S.
NUCLEAR REGULATORY CONNISSION
REGION V
Report Nos:
Docket Nos:
License Nos:
Licensee:
50-528/87-01, 50-529/87-01, 50-530/87-02
'0-528, 50-529, 50-530 NPF-41, NPF-51, CPPP,-143 Arizona Nuclear Power Project P. 0.
Box 52034 Phoenix, AZ. 85072-2034
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Inspectors:
C. Bosted, Resident Inspector J.
a
,
ess ent nspector K. Ivey, esl ent nspector Approved By:
S.
Rlc ards, C ref, ng)neersng Section Ins ection Conducted:
January 5, 1987 - February 20, 1987
%OR immerman, en>or ess ent nspector G. Fiore i, essdent Inspector 3->5-Sl ate
)gne 3-13-8 l Date Signed 3-tE-8 l Date Signed
'3-l3 - S1 ate sgne 3-'l3-81 ate sgne 3-3 3-8 ate Signed Summary:
Ins ection on Januar
1987 - Februar
1987 Re ort Nos. 50-
an
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N 1, tt.
Nl db Ably
d
by the five resident inspectors.
Areas inspected included: followup of previously identified items; review of plant activities; plant tours; engineered safety feature system walkdowns; surveillance testing; plant maintenance; emergency diesel problems; Surry event lessons learned; review of heavy lift procedures; preoperational test results reviews; operational staffing and training; plant procedures; proposed Technical Specilication review; fuel receipt and storage; licensee event report followup; periodic and special reports review; IE Bulletin followup; Generic Letter followup, and allegation followu,I If f
)
-2-During this inspection the following Inspection Procedures wexe covered:
30702, 30703, 36301, 41301, 42400, 42450, 42451, 42452, 6050lg 61700, 61715, 61720, 61726, 62703, 70325, 70329, 71301, 71302, 71707, 71710, 90711, 92700, 92701, 92703, 93701, 93702.
Results:
Of the 19 areas inspected, two violations were identified.
paa>
ore to perform a channe1 check of the log power reactor protective instruments - paragraph 7; and failure to properly post a radiation area
- paragraph I f
f
DETAILS Persons Contacted:
The below listed technical and supervisory personnel were among those contacted:
Arizona Nuclear Power Pro ect ANPP
- R J.
- L R.
J.
B.
J.
W.
- D.
- J M.
J.
A.
D.
- R.
- G.
J.
F.
- T.
L.
E.
- R.
- O Adney, Operations Superintendent, Unit 2 Allen, Operations Manager Brown, Radiation Protection and Chemistry Manager Buckhalter, Outage Management Superintendent, Unit 3 R. Bynum, PVNGS Plant Manager Cederquist, Chemical Services Manager Dennis, Operations Supervisor, Unit 1 Fernow, Training Manager Gouge, Operations Superintendent, Unit 3 G. Haynes, Vice President, Nuclear Production E. Ide, Corporate guality Assurance Manager Jump, Startup Manager, Unit 3 Kirby, Project Transition Manager McCabe, Assistant Startup Manager, Unit 3 Nelson, Operations Security Manager Nelson, Maintenance Manager Perkins, Radiological Services Manager Pollard, Operations Supervisor, Unit 2 Riedel, Operations Supervisor, Unit 3 Shriver, Compliance Manager Souza, Assistant guality Assurance Manager E..Van Brunt, Jr., Executive Vice President Younger, Operations Superintendent, Unit 1 Zeringue, Technical Support Manager The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
- Attended the Exit Meeting on February 19, 1987.
Previousl Identified Items Unit I Closed Unresolved Item 528/86-37-01
Emer enc Li htin
.
This matter dealt with the operability of the Unit I emergency lighting system associated with equipment used to shutdown the plant from outside the Control Room.
The emergency lighting system was tested by the licensee in December 1986, after a long delay due to coordination and communication problems among various organizational units.
During the test, battery voltage dropped below a
predetermined level resulting in the termination of the test and the
e I
prompt implementation nf a design change which provided additional battery capacity to the lighting system.
Following the change, the system demonstrated that the required light intensity could be provided by the system following an eight hour test of the batteries.
Fi'nal:Safety Analysis Report (FSAR); paragraph.9.5.3.2.2.3 states that the areas.needed for the operation of safe shutdown equipment are supplied by batteries designed to provide rated lighting for a minimum continuous period of eight 'hours.
In addition, the Detailed Design Criteria for the emergency lighting system, section 1.36, specified an illumination of three foot candles at the remote shutdown panel'.
Inspector review determined that the licensee's preoperational testing acceptance criteria was based on a minimum voltage, rather than, assuring a minimum light intensity.
The inspector stated; therefore, that a correlation between the preoperational test acceptance criteria.and the FSAR design statement, as well as the emergency lighting system Detailed Design Criteria could not readily be shown.
The licensee representative acknowledged -the.inspector's:cooment
.and stated that a historical review of the emergency lighting system design and test results would be performed.
Based on the inspector's verification that areas required for safe shutdown currently satisfy regulatory requirements, this item is being closed.
However, the licensee's actions to review the implementation of the original design will be followed in a future inspection (529/87-01-01).
Unit 2 Closed Unresolved Item 529 86-20-02
- Reactor Coolant S stem RCS Pressure Iso at>on a ves.
This "item dealt with the leakage surveillance testing required by Technical Specification (TS) 4.4.5.2.2.d following flow through the RCS pressure isolation valves.
The licensee issued temporary procedure change No.
9 to Revision 2 of procedure 73ST-9SI03, Leak Test of Reactor Coolant System (RCS) Isolation Valves, requiring, in-part, that check valves, SIE V540, V541, V542 and V543 be leak tested following a safety injection actuation even if there is no flow into the reactor coolant system.
This results from the fact that a small amount of flow will pass through the valve as pressure increases from about 600 psig to approximately 1800 psig; the shutoff head of the high pressure safety injection pumps.
In addition an ANPP internal memorandum (497-JMA-95.52),
issued shortly after the close of the inspection period on February 18, 1987, reiterated that TS 4.0.4 is applicable to TS 4.4.5.2.2.d for Node
and I entry.
This item is closed.
Review of Plant Activities a.
Unit I The unit operated at full power until January 10, when a
reactor power cutback (RPCB) occurred when both main generator
I
output breakers opened.
Reactor power initially stabilized at 405; however, a rector trip occurred on high level in No.
Steam Generator due to difficulty in maintaining feedwater control.
The cause of the trip was due in part to 'personnel error.
The operator used master manual, manual individual, and automatic feedwater control in an effort to stabilize steam generator levels; however, control was aggravated when the individual did not match demand signals prior to shifting from manual back to automatic control.
The licensee has issued instructions to maximize use of automatic control during feedwater transients, and to use master manual rather than manual individual as much as possible if manual control is considered necessary.
The cause of the RPCB was determined to have resulted from a malfunctioning sub-synchronous relay in the main generator protective circuit.
The failed component was sent to the supplier to determine the cause of the failure.
The plant returned to power on January 11.
On January 17 a valid high radiation alarm was received on the No.
1 Steam Generator blowdown system radiation monitor.
Sampling determined that there was a primary to secondary leak in the No.
1 Steam Generator and a reactor coolant system (RCS)
inventory calculation determined the leakage to be approximately 0.2 gpm.
Continued inventory calculations showed that the leak increased to 0.4 gpm before stabilizing.
The licensee commenced shutdown of the unit at 6:05 PM on January 18 and entered Mode 5 at 2:47 AM on January 20.
The unit remained in Mode 5 for the remainder of the reporting period while the licensee conducted steam generator eddy current testing and tube plugging activities.
Unit 2 Unit 2 was shutdown on January 9 from a power level of 100K for a planned major outage.
Principal outage activities included the performance of integrated safeguards testing; a major inspection of both emergency diesels (paragraph lO);
performance of numerous Technical Specification required surveillance tests; repair'of Control Room annunciator problems; eddy current testing and plugging of steam generator tubes; and, implementation of several plant design changes.
Completion of planned outage work to date has progressed with a minimum of problems.
Startup is currently scheduled for early Miarch.
Unit 3 During this report period, the licensee began receiving fuel in anticipation of issuance of a low power license and commencement of fuel loading in Unit 3.
At the close of this inspection, 145 of 241 fuel assemblies needed for the initial core load had been received, inspected, and placed in dry storage in the spent fuel pool.
The licensee's efforts to repair the emergency diesel generator engine which was damaged
r
during preoperational testing on December 23, 1986, continued through this report period.
..The license also began performing surveillance tests required to assure operability of equipment necessary for Node 6.entry.
The licensee considers construction activities to be 99% complete in,Unit -3 with, initial fuel loading anticipated to occur in the.fifst quarter of 1987.
d.
Plant Tours The following plant areas at Units 1, 2 and 3 were toured by the inspectors during the course of the inspection:
o Auxiliary Building o
Containment Build'ing o-Control Complex Building o
Diesel Generator Building o
Radwaste Building o
-.,Turbine. Building.--
'
~
Yard Area and Perimeter
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'he following areas were observed during the tours:
l.
0 eratin Lo s and Records Records were reviewed against Technical Specification and administrative control pro-cedure requirements.
2.
Monitorin Instrumentation Process instruments were o served or corre ation etween channels and for con-formance with Technical Specification requirements.
A problem associated with the method of performing channel checks of the log power reactor protective instruments is documented in paragraph 7.
3.
~Shif M
i C t i
d iaaf i
g observed for conformance with 10 CFR 50.54. (k), Technical Specifications, and administrative procedures.
, 4.
E ui ment Lineu s
Valve and electrical breakers were verified to e in the position or condition required by Technical Specifications and administrative procedures for
-
~ - the applicable plant mode.
This verification included
" -- routine control board indication reviews and conduct of partial system lineups.
5.
E ui ment Ta in Selected equipment, for which tagging requests had been initiated, was observed to verify that tags were in place and the equipment in the condition specified.
6.
General Plant E ui ment Conditions Plant equipment was o served for indications o
system leakage, improper
0 f
I
lubrication, or other conditions that would prevent the system from fulfillingfunctional requirements.
Fire Protection Fire fighting equipment and controls were i
i ii ii i ii ii'dministrative procedures.
Plant Chemistr Chemical analysis results were reviewed for con ormance with Technical, Specifications and admin-istrative control procedures.
Securit Activities observed for conformance with regu atory requirements, implementation of the site security plan, and administrative procedures included vehicle and personnel access, and protected and vital area integrity.
On January 13 the inspector discovered 'an unattended Automated Control Access Device (ACAD) lying on the ground by the Service Building inside of the protected area.
ACADs are key card picture badges used to access vital and protected areas.
Security took imnediate corrective action by cancelling the ACAD on the security computer and locating the responsible individual.
Subsequent review of the computer transaction log verified that the ACAD was used to enter the protected area only four minutes earlier and no unauthorized transactions were made with the ACAD.
The licensee has had previous problems with lost ACADs and has set up measures to ensure that personnel are aware of their secur ity responsibilities.
A review of the number of lost ACADs on a month-by-month basis for the previous year verified that the measures have reduced the number of lost ACADs.
A steadily decreasing trend was apparent since June, 1986, with the exception that an increase was noted during unit outages in December, 1986, and January, 1987.
At the exit meeting the inspector noted that even though an increase in lost ACADs can be expected during outages in which the number of new individuals with site access is increased, the licensee should not consider this acceptable and should continue with all present efforts to reduce ACAD losses to a minimum.
The licensee stated that there were no plans to reduce any of the corrective or preventive measures that were in place.
Plant Housekee in Plant conditions and material/
equ>pment 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.
Radiation Protection Controls Areas observed included control point operation, records of licensee's surveys
l
I I
I i
t
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.
A problem noted in the posting of-a radiation-'area.in,the Unit 1 Turbine Building is documented in paragraph 8.
En ineered Safet Feature ESF S stem Walk Down - Units 1 and
tse
~ s 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.
The inspector also verified that the system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Unit 1 Accessible portions of the following systems were walked down on the indicated date.
~Ss tern 125V DC Electrical Distribution, Channels
"A" and "B" Date January
Chemical Spray System, Trains "A" and "B",,"
Containment Spray Systems, Trains "A" and "B" January
January
Essential Cooling Water, Trains "A" and "B" January
High Pressure Safety Injection, Trains "A" and B" January
Low Pressure Safety Injection, Trains "A" and "B" January
Diesel Generator Systems, Trains "A" and "B" January
Essential Spray Pond System, Trains
"A" and "B"
Shutdown Cooling System, Trains "A" and,"B" February 5,
February
I I
'
Unit 2 Accessible portions of the fo11owing systems were walked down on the indicated dates.
~Sstem Safety Injection Tanks "A", "B", "C" and
"D" Shutdown Cooling Operation Boration Flow Path Diesel Generator System, Train "A" Date January
January
January
February
Essential Cooling Mater System, Train "B" February
Essential Spray Pond System, Train "B" February
Control Room Emergency Filtration System, Trains "A" and "B" February
No violations of NRC requirements or deviations were identified.
5.
Surveillance Testin
- Units 1 and
a.
Surveillance tests required to be performed by the Technical Specifications (TS) were reviewed on a sampling basis to verify that:
1) the surveillance tests were correctly included on the facility schedule; 2)
a technically adequate procedure existed for performance of the surveillance tests; 3) the surveillance tests had been performed at the frequency specified in the TS; and 4) test results satisfied acceptance criteria or were properly dispositioned.
b.
Portions of the following surveillances were observed by the inspector on the dates shown:
Unit 1 Procedure 73TI-9RC01 Descri tion Steam Generator Eddy Current Examinations Dates Performed January 4 and
77ST-9SB09 CPC Channel
"C" Functional Test January
36ST-1SE03 Excore Safety Linear Channel quarterly Calibration January
f e
41ST-1DG02 Diesel Generator
"B" Test - 4.8.1.1.2.a January
Unit 2 P
~D Dates Performed 73ST-9CL01
Containment Leakage Type
"B" and "C" Testing Isolation Valves SIA 164, SIC 321, SIA 523, and SIA 672 Electrical Penetrations 37, 38, 39 and 40 January 13,
February
36ST-9SI03 Safety Injection System January 14,
Instrumentation Surveillance Test - Shutdown Cooling 36ST-9SB44 RPS Matrix Relays to Reactor Trip Response Time Test January
72ST-2RX09 Shutdown Margin January
42ST-2SI12 Shutdown Cooling January
73ST-2DG02 Class 1E Diesel Generator February
and Integrated Safeguards Surveillance No violations of NRC requirements or deviations were identified.
6.
Plant Maintenance - Unit 1 and
a ~
During the inspection period, the inspector observed and re-viewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements, compliance with administrative and maintenance procedures, required QA/QC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified reportability for these activities was correct.
b.
The inspector witnessed portions of the following maintenance activities:
Unit 1 Descri tion o
Troubleshoot Loss of Speed Control on Diesel Generator
"B" Dates Performed January
/I
o Portions of Maintenance Outage Work January
on Train "A" High Pressure Safety Injection o
Portions of Various Maintenance on Train "A" Charging System o
Steam Generator Eddy Current Testing and Tube Plugging Unit 2 o
Inspection of Train "A" Emergency Diesel Turbocharger January
January 5-18 Dates Performed January
o Portions of Teardown and Restoration January 12, 13, of Train "A" Emergency Diesel 14, and 20 o
Cleanup of "A" Class 1E Battery January
Terminal Connection Plates o
Replacement of Train "A" Emergency Diesel Governor Oil January
o Sealing of Conduit Penetration (2EZA1CATRAJ)
February
o Installation of the Fuel Lines on the Train "A" Diesel February
No violations of NRC requirements or deviations were identified.
7.
Neutron Flux Lo Power Channel Check On January ll, 1987, with the plant in Mode 3, the inspector questioned the licensee's method of accomplishing the log power reactor protective instrumentation channel checks, required to be performed shiftly by Technical Specification (TS) 4.3.1.1.
The inspector reviewed surveillance procedure 41ST-1ZZ31, Revision 0, Mode 3 Surveillance Logs, to determine the acceptance criteria used to satisfy the channel check.
The procedural acceptance criteria included verification that the "power on" light was lit, and'the trouble light was off.
The inspector concluded that the above acceptance criteria did not satisfy the Technical Specification 1.5 definition of a channel check, which requires a qualitative assessment of channel behavior by the comparison of each channel indication with other indications derived from independent instrument channels measuring the same parameter.
Subsequent inspector review determined that from 10:20 PM, January 9 through 11: 15 AM, January 11, 1987, the shiftly channel check was not performed in accordance with Technical Specification 1.5, in that a qualitative comparison between channels was not conducted through the implementation of 41ST-1ZZ31.
Failure to perform the required
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channel checks is contrary to TS 4.3. 1.1 and is considered a
violation (528/87-'01-01).
During-the inspector's observations noted above, Channel
"C" log power was indicating lOXE-7X power which was in contrast, to the other three log power protective channels which indicated 10NE-6X power.
The inspector discussed his concern with the shift supervisor, who after review, declared the "C" log power channel inoperable.
Historically, the "A" and
"D" log power channels have read approximately a decade higher than the "B" and "C" channels at low power levels (lONE-8$ - lONE-7X) because of the proximity of the detectors to two startup neutron sources in the reactor vessel.
During the approach to criticality the four channels normally come into agreement at about 10'-5X power, as the neutron population offsets the l'ocation of the detectors to the startup sources.
The inspector witnessed the subsequent reactor startup on January 11, and observed good correlation between all channels during the approach to criticality.
Subsequent licensee evaluation determined that the "C" channel was reading appropriately; however, the "B" channel had been reading high at low power (lONE-6X), and an adjustment was made.
Further, during the inspector's review it was noted that the plant protection channels were bypassed one at a time between January
and ll to perform a functional check of the auctioneered power supplies.
The restoration steps for each channel did not include verification prior to retesting the channels since the previously preformed channel checks were completed within the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> plus 25K required by Technical Specifications, and remained valid.
Although no problems were identified in this specific instance, the inspector noted that the routine shiftly channel checks were performed at 9:23 AN, January 11.
Mhen the "C" channel was bypassed for the above power supply check, the "C" channel was excluded from the shiftly channel check.
Channel checks of all channels were performed at ll:15 AM, following returning channel
"C" to service, but only in preparation for Node 2 entry, as required by procedure.
The inspector stated that had it not been for the impending mode change, channel
"C" would have apparently remained on its own
"clock" for completing the required channel check.
Licensee management acknowledged-the inspector's comments and stated that a
night order will be issued and operating procedures will be revised to ensure instrument channels which have been removed from service are channel checked prior to being declared operable.
The inspector will follow the licensee's actions (528/87-01-02).
Radiation Area Postin
- Unit. 1 On January 21 at approximately 9:00 AM'he inspector noted that the Unit 1 100 foot elevation of the Turbine Building had been posted as a radiation area.
However, the inspector identified an entrance into,the Turbine Building from the 13.8 kv non-class switchgear room (door No. T-104) which was not posted.
This room can be accessed from the non-class battery room through door Nos.
115 and 116 which
9.
also were not posted.
A radiation protection (RP) survey which was completed at 10:30 AM, on January 21 showed readings of up to 20 millirem/hour (mr/hr) general area in the vicinity of the steam generator blowdown lines.
Review of the RP logs revealed that the posting of the lbO foot elevation of the Turbine Building was made at 11:10 PH on January
due to draining of Steam Generator No.
1 through the blowdown lines, and the presence of 100 mr/hr contact radiation readings on those pipes as a result of a primary-to-secondary leak.
The decision to
. post the entire 100 foot elevation as a radiation area was made approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> before the inspector identified the posting error.
CFR Part 20 requires that any area reading five mr/hr or more, be conspicuously posted as a radiation area.
The failure to post all access points into an area with a general area radiation reading of 20 mr/hr is a violation of NRC requirements (528/87-01-03).
A similar posting problem was identified in the Containment Building on January 22 during a review of the temporary reactor coolant system (RCS) water level indication in the lA Reactor Coolant Pump (RCP) bay.
The inspector noted that the 80 foot elevation door to the 1A RCP bay was posted as a high contamination area and the 100 foot elevation door to the 1B RCP bay was not.
Stairs and walkways that connect the two RCP bays allow access to either bay from both doors.'
walkdown confirmed that there were no physical or posting barriers between the two bays to identify the posting change.
The licensee's posting procedure (No. 75RP-OZZ01, Radiological Posting) gives loose surface contamination limits of 1;000.disintegrations per minute (dpm)/100 square centimeters (cm)
for a contamination area and 50,000 dpm/100 square cm for a high contamination area.
The entire Containment Building was posted as a
radiation and contamination area.
Subsequent review of RP surveys revealed that no area of high contamination existed in either of the RCP bays at the time of the posting discrepancy.
In both instances the licensee decided to post large areas as a
conservative measure until more detailed radiological surveys could be accomplished.
The inspector stated that although this methodology appeared sound, it was not properly accomplished.
Steam Generator Activities Unit 1 On January 17, Unit 1 experienced a tube leak in the No.
1 Steam Generator and the unit was subsequently shutdown on January 20.
The licensee performed visual examinations and,eddy current testing in both steam generators (SGs) to determine the cause and extent of the tube damage.
Eddy current testing (ECT) confirmed the leak to be on the cold leg side adjacent to the first eggcrate support on the row 3, colum~
2 tube.
Continued ECT discovered additional concerns as follows:
'1 I
a)
Tube Rear - Indications of tube wall thinning were found on 13 aaa~tional tubes in SG No.1 and 9 tubes in SG No.
2 in the cold leg corner region.
Evaluation of the ECT data determined the indications to be typical of that caused by tube-to-support wear resulting from 'tube vibration.
The cause of. the tube vibration is postulated.to be local, high radial.velocity streaming of downcomer recirculating fluid on the cold leg side.
No indications of wear were found on the hot leg side.
The"licensee has plugged and.staked all tubes with any wear indication in the local high velocity region.
All unplugged tubes in the region of interest will be reinspected during the next refueling outage to confirm that wear has not initiated in these tubes.
b)
Dented Tubes and Potential Loose Part's - Eddy current testing an i eroptic inspect>on in No.
1 confirmed that tubes on the cold leg side in row 1 at columns 48 through
(9 total) had indentations of approximately 1/16 to 1/8 inches at the elevation of the top surface of the flow distribution plate.
Evaluations of ECT data and laboratory mockup testing confirmed that the dents were apparently caused by a metallic foreign object located between the economizer divider plate and the row 1 tubes.
While precise identification of the object cannot be made, it is possible that it remained from the original construction of the steam generator.
Engineering evaluation verified that the strain caused by denting of the tubes is well below the threshold value for tube cracking.
The object is believed to be wedged in place, and is located in a relatively low velocity flow field making relocation improbable.
The licensee does not currently plan to remove the object since it would require removing a tube.
However, the licensee has planned to monitor selective dented tubes during a future eddy current.inspection to confirm the non progression of the tube dents with time.
c)
Tube De osits - During eddy current testing (ECT), foreign resi ue was iscovered inside approximately 100 tubes on the hot leg side in SG No. 1.
Chemical analysis indicated that the deposits consisted of an organic material, crud, and boric
'... acid..
Comparison of chemical analysis results gave reasonable
'ssurance that 'the residue was from 'yellow herculite "(a yellow sheeting material used to cover components to maintain cleanliness).
The licensee hypothesized that the herculite was present in the hot leg piping or in the steam generator plenum prior to fuel load.
However, the presence of non activated species (found in herculite) in the deposits indicates that the organic material did not travel through the reactor vessel.
Laboratory analysis concluded that impurity releases resulting from the decomposition of the herculite could be effectively removed by purification and therefore had no adverse affects on the steam generator.
Videography results indicated that the effective tube surfaces were relatively clean following the completion of ECT (deposits removed by the ECT probe).
During the videography, a solid mass, approximately 5/8 inches wide
0, 0'
was found in one tube in SG No. l.
The object was pulverized by a vacuum device during removal and could not be analyzed.
The licensee concluded that the object was non related to the foreign residue in the tubes.
The licensee plugged 22 tubes with wear indication,'
tubes with dent indications, and 6 other tubes not associated with wear.
Tubes with wear and dent indications were also staked to prevent severing or collapse of the tubes.
Eddy current testing will be conducted during the first refueling outage in the wear prone areas and in the tubes adjacent to the object in SG No. 1.
Combustion Engineering was involved in all evaluations and corrective actions performed by the licensee.
Uriit 2 The steam generator tube wear phenomenon was also noted in the cold leg corner region at Unit 2.
Following eddy current testing, the licensee plugged and staked 51 tubes with wear indication.
A meeting was held on February 24, 1987, between the licensee, CE and NRR to discuss the results of the Units 1 and 2 steam generator findings as documented above.
NRR concluded that the licensee's corrective actions appeared appropriate.
10.
Emer enc Diesel Generator DG Maintenance - Units 1 and 2.
Unit 2 Major inspection and preventative maintenance efforts on the emergency diesels were expanded from the planned outage efforts to include the lessons learned from the Unit 3 "8" emergency diesel cracked piston rod experience.
The No.
9 left rod from the "A" DG was replaced because it had been plated similarly to the rod which had failed at Unit 3.
An inspection of the rod revealed no crack indications.
The No.
3 left rod of the "A" DG was also replaced for inspection purposes because it had been nickel sprayed, a process which replaced the iron plating process that led to the rod failure at Unit 3.
No crack indications were noted.
Other nickel sprayed rods were also ultrasonically tested for cracks.
No indications were noted.
On February 8 during the performance of a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run on the "A" DG, which was part of an integrated safeguards test, leaking diesel fuel from the No.
5 right fuel injection line ignited and burned.
Fire alarm systems worked as required.
The fire suppression system did not activate as the temperature was not high enough to melt the fusible links.
The fire was extinguished by the plant fire department.
Although the response to the fire alarm system was satisfactory, sensitivity to rapid response to fire alarms was discussed with licensee managemen i
Host of the damage to the engine was limited to components in the vicini.ty of the No. 4, and 5 right cylinders.
Damaged components have since been replaced.
A visual inspection at the time of the fire revealed that the injection line had pulled out of the compression fitting at the fuel injector.
The DG supplier and ferrule manufacturer were both contacted, and were involVed in assessing the cause of the failure and developing corrective actions..
The root cause of the fitting failure was attributed to an improper installation of the ferrule on the fuel line by the supplier.
The fuel line was procured as a spare, and was not the original fuel line and fitting.
The licensee replaced all 20 fuel line fittings on the Unit 2 "A" DG and replaced the fittings on one fuel line on the "B" DG which had also been procured from the vendor as a spare.
The method of installing the new ferrule was based on evaluations and tests conducted by the licensee with cooperation from a local laboratory and support from the vendors.
Unit 1 The licensee also replaced all fuel lines which were procured as spares from the vendor on both DGs at Unit 1. There were seven fuel line fittings replaced on the "A" DG and two line fittings replaced on the "B" DG.
However, during DG operation to test the new ferrule installations, one line separated on the "B" DG on February 16 and one line separated on the "A" DG on February 21.
At the end of this reporting period, the licensee was continuing to investigate the cause of the failures and the adequacy of the installation method.
The inspector will continue to follow the licensee's corrective actions (528/87-01-04).
No violations of NRC requirements or deviations were identified.
Surr Event Lessons Learned Followu
- Units
2, and
Following the Surry plant event, several potentially generic items were identified which were reviewed by the inspector to determine if the Palo Verde site was susceptible to similar conditions.
These items included:
Secondary water intrusion into the fire suppression system causing inadvertent system actuation.
Pipe wall thickness degradation.
Feedwater check valve maloperation.
In following up these items, the inspector reviewed procedures, surveillance packages and completed work orders.
Interviews were also conducted with members of the plant management staff to determine what actions the licensee had planned.
A review of the fire protection system by the inspector determined that the Turbine Building fire suppression system is a pressurized water system with a manually operated actuation system.
Carbon dioxide and Malon are not used in the Turbine Building.
The system is not expected to be
inadvertently operated by water intrusion because of the manual actuation.
The main feedwater check valves are routinely surveilled following a plant heatup or cooldown.
Surveillance procedures 73ST-IZZ07, 73ST-2ZZ07, and 73ST-3ZZ07, "Section XI Testing of Secondary Check Valves," for Units I, 2, and 3, specify that the economizer and downcomer check valves be tested following a cooldown to cold shutdown or a heatup from cold shutdown, if possible, and at least once every 18 months.
The surveillance verifies that the valves close when a reverse differential pressure is applied.
The inspector reviewed the completed satisfactory surveillance procedures performed since operation commenced for Units I and 2.
The licensee has conducted studies intended to identify a series of balance of plant piping components which have a susceptibility to wall erosion from steam, water and steam/water flows.
A preventive maintenance program is being established to ultrasonically test the pipes and components.
The program will be described in a procedure when finalized.
Examples of systems to be monitored are extraction steam lines, sections of feedwater lines and condensate lines.
Several sections of the letdown and charging lines have also been identified for monitoring.
This program was initiated prior to the Surry 2 incident and will be performed during the Unit I refueling outage.
No violations of NRC requirements or deviations were identified.
Review of Heav Lift Procedures
- Units
2 and
A review of plant procedures and manuals used for heavy lifts within the reactor Containment, and Fuel Building was conducted.
The procedures and manual were compared to the recommendations contained in NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants".
Procedures reviewed were 31MT-9RC02, "Reactor Vessel Disassembly and Assembly" and 31MT-9RC06, "Reactor Coolant Pump Disassembly and Assembly".
Procedure 31MT-9FH02, "Operation of 10 Ton and 150/15 Ton Fuel Building Cranes" has been incorporated into the PYNGS Rigging Manual, which was also reviewed.
The inspector noted that the weight of the major loads were listed in the procedures and diagrams were listed for the approved application of the listed lifting equipment.
Generally, the Ouality Control department was involved with hold points prior to lifts to insure that the liftrig was properly installed.
Load cell weights and lift speeds were specified in the procedures.
The inspector noted that procedure 31MT-9RC02 did not require the crane operators to be certified per ANSI 30.2-1976, as recommended by NUREG 0612.
Maintenance Supervision stated that the inspector's comment would be reviewed during the next revision of the procedure.
No violations of NRC requirements or deviations were identified.
Prep erational Testin
- Unit 3
'
a.
Prep erational Test Results Evaluation Yerification The inspector reviewed the licensee's program. for assuring preoperational test results are evaluated in a manner consistent with regulatory requirements and the Ticensee's comitments.
The following administrative control procedures governing the review of startup test results were reviewed as a
part of this inspection:
P d
~d 90AC-OZZ09 90AC-OZZ17 90AC-OZZ18 Startup Test Working Group Startup gualifications, Certifications and Testing
- ~.
Startup Test Results Review From this review, the inspector was able to ascertain that the program for reviewing preoperational-test results established by the licensee was consistent with the licensee's commitments and regulatory requirements with regard to evaluation of test data, resolution of test exceptions, verification of acceptance criteria and issuance of test reports.
The inspector also found the qualifications established for personnel engaged in performing these activities to be consistent with the licensee's commitments and regulatory requirements.
The inspector further reviewed the licensee's weekly Unit 3 Testing Status Report and discipline test schedules (DTS), and on a
sampling basis established that the licensee has reviewed or has scheduled the review of the results of all required preoperational tests.
b.
Prep erational Test Results Review The results of the Reactor Protection System Tests, 92PE-3SB10, 11, 12, and 13 were reviewed by the inspector.
The inspector verified that activities such as test data acquisition, test exception resolution, test report issuance, test modifications and acceptance criteria verification had been accomplished in accordance with procedures.
No violations of NRC requirements or deviations were identified.
14.
0 erational Staffin
- Unit 3 During this inspection, the inspector reviewed the qualifications and level of experience of managerial and operating staff personnel responsible for the conduct of operations in Unit 3 for conformance to the licensee's FSAR commitments to ANSI/ANS 3.1 - 1978, for selection and training of nuclear power plant personnel, and.for conformance to the proposed Technical Specifications for Unit 3.
On a station level, this included a review of the qualifications and experience of the individuals currently holding the following staff positions:
Plant Manager, Operations Manager, Technical Support
l (
Manager, Reactor Engineering Supervisor, Radiation Protection and Chemistry Manager, Chemistry Services Manager, and Radiological Services Manager; and, on a unit specific level, the qualifications and experience of the Unit Operations Superintendent, Da'y Shift Supervisor and the six licensed shift supervisors and 'their assistants.
All were found to meet or exceed the minimufo.,specified requirements.
No violations of NRC requirements or deviations were identified.
15.
Review of Trainin and uglification Pro rams - Unit 3 The licensed and non-licensed operator training program currently in effect was previously reviewed and documented in Inspection Reports 528/86-33 and 528/86-37 for Units I and 2.
Operators for Unit 3 have been included in the same training programs as the other units.
The training programs were reviewed and compared to the requirements of 10 CFR 55, Appendix A and NUREG-0737.
The current staff training was found to be acceptable during the above inspections, and the inspector did not find any changes in the training program as it pertained to Unit 3 personnel.
No violations of NRC requirements or deviations were identified.
16.
Plant Procedures
- Unit 3 a.
Procedure Control S stem The inspector reviewed the licensee's system for development,
'eview, implementation and control of plant procedures for Unit 3.
The program and procedures governing the control and use of plant procedures in Unit 3 are the same as for Units I and 2 and as such have been reviewed previously.
As a part of this inspection, the following station procedures outlining the licensee's procedure control system were again reviewed with emphasis placed on the review of any recent changes:
Procedure TOHFZ'21T7 70AC-OZZ02 70AC-9ZZ06 78AC-OZZ01 Descri tion escr>ptson and Use of Plant Policy, Procedures and Instructions Review and Approval of Station Procedures Temporarily Approved Procedure Change Nuclear Operations Document and Manual Control The inspector also reviewed a current station manual index noting in particular any recent procedure additions or deletions.
During the course of this review, the inspector did note that some safety-related system operating and maintenance procedures were not designated as requiring periodic nuclear safety reviews.
Further investigation; however, did not identify any instances in which a procedure requiring a
periodic review had not been reviewed within the past two years as required.
The discrepancies in the procedure index were brought to the attention of the licensee.
The licensee
'
acknowledged the need to update the procedure index to assure that the required reviews are appropriately flagged in the future.
b.
c ~
,During this inspection, the inspector also re-reviewed the
'icensee's stated policy with regard to adherence to plant procedures, the use of temporary instructions, standing orders, and maintenance or operating logs, as specified in administrative control procedure 40AC-9ZZ02, Conduct of Shift Operations.
The inspector found the stated policies to be consistent with regulatory guidance with regard to the overall
-"conduct'f safety-related activities.
0 eratin Procedures., ',
It The inspector reviewed a sample of plant specific operating procedures developed for use in Unit 3.
Due to the similarities in the design and construction of Unit 3 to Units 1 and 2, the inspector found the procedures developed for use in Unit 3 to be largely the same as those for Units 1 and 2.
No significant differences in either format or content were identified.
The procedures reviewed were all found to contain a stated objective, a listing of precautions and limitations, prerequisites for performance, and step-by-step instructions.
Detailed valve line'-up check sheets, electrical check lists and necessary data acquisition sheets were also found to be provided.
Procedures reviewed included procedures for the placing of safety-related equipment into service, startup and shutdown of the reactor, and response to alarm conditions.
All were found to have received the required nuclear safety reviews prior to their inclusion in the station manual.
Maintenance Procedures The inspector reviewed the licensees'rogram and procedures for the control of safety-related work.
The work control program and procedures are the same for all three units.
The following program and administrative control procedures were again reviewed as a part of this inspection with. emphasis placed on the review of recent changes:
Procedure Descri tion 30PR-9ZZ01 30AC-9ZZ01 30AC-9ZZ02 40AC-9ZZ14 Maintenance Program Work Control Preventive Maintenance Station Tagging and Clearance The inspector also reviewed a selection of maintenance, calibration and surveillance procedures for specific pieces of safety-related equipment.
The inspector found these procedures to be consistent in format and content.
The inspector verified that the required reviews had been accomplished prior to issuance of the procedure On a selected basis, the maintenance and calibration procedures reviewed were checked for technical adequacy by the inspector.
'.
Emer enc Procedures The inspector reviewed the emergency procedures developed for use in Unit 3.
The procedures for Unit 3 were found to be identical to those for Units 1 and 2 in both format and content.
These procedures include a single emergency operating procedure, 43EP-3ZZ01, nine recovery procedures from specific events, and a functional recovery procedure intended for use when a specific event cannot or has not been diagnosed.
Following a cooldown event at Unit 1 oh July 12, 1986, concerns were identified to the licensee with regard to apparent inconsistencies with the procedures in use at the time and the approach to the use of the functional recovery procedure.
Discussions between the licensee, NRR and the region V staff have not resolved all concerns to date.
These concerns are being tracked as open item 528/86-24-02.
No violations of NRC requirements or deviations were identified.
17.
Pro osed Technical S ecification Review - Unit 3 A review of Unit 3 proposed Technical Specifications was performed to insure that the specifications covered conditions that would be expected in the plant.
Clarity, understandability, and enforceability were considered during the review.
The proposed Unit 3 Technical Specifications are very similar to the Technical Specifications for Units 1 and 2.
Some minor items were noted during the review and were brought to the attention of NRR.
No violations of NRC requirements or deviations were identified.
18.
Fuel Recei t and Stora e - Unit 3 The inspector reviewed the licensee programmatic controls for the receipt, handling, inspection and storage of new fuel assemblies in Unit 3.
The following procedures were reviewed during this inspection:
Procedure 72AC-9ZZ01 72MT-9FHOl 430P-3FX03 72AC-ORX01
~0i ti Control of Special Nuclear Material Transfer and Inventory New Fuel Handl,ing Operation of the Spent Fuel Handling Machine Response Plan for Severe Damage to New Fuel Assemblies The inspector also witnessed during this inspection on a periodic basis the handling of a number of new fuel elements.
This included witnessing the lifting of new fuel canisters, radiological surveys,
l 0'
20.
the upending of fuel assemblies, visual inspection of the assemblies, and the transport and placement of the assemblies into storage locations in the spent fuel pool.
No violations of NRC requirements or deviations were identified.
Closed Tem orar Instruction TI-2500/16: "Incore Flu'x Ha in and Sea a
e
-
nsts 1,
2 and
The inspector reviewed the licensee's followup of the design adequacy of the movable flux mapping system in light of the problem documented in IE Information Notice 85-45., This matter was refer red to Combustion Engineering (CE) by the licensee.
CE concluded in correspondence to the licensee that the system design is in accordance with approved design specifications and that the effects of a safe shutdown earthquake at the Palo Verde Nuclear Generating Station (PYNGS) had been considered.
This item is closed.
No violations of NRC requirements or deviations were identified.
Alle ations Followu
- Unit 3.
Al le ation RV-86-A-101 Characterization During hot functional testing in Unit 3 a problem was identified with a thermowell in a resistance temperature detector (RTD) nozzle in the reactor coolant system.
While removing the thermowell for replacement, the threads were galled and excessive radial and axial force was applied to free the stuck thermowell.
This excessive force caused the upper nozzle body to be twisted.
It was alleged that the licensee personnel involved straightened the nozzle and pronounced it satisfactory without non destructive examination of the partial penetration weld and against the advice of the manufacturer.
Im lied Si nificance to Plant Desi n, Construction or 0 erations A potential for failure of the thermowell nozzle exists and could result in a significant loss of reactor coolant inventory.
Assessment of Safet Si nificance This allegation was forwarded by the NRC to the licensee requestino a formal response.
In the licensee's response, documentation was provided indicating that a nonconformance report was written at the time the incident involving the twisting of the nozzle occurred, and although initially a use-as-is disposition was sought, the nonconformance report was ultimately dispositioned to require replacement of the nozzle.
The inspector determined that the nozzle has not as of yet been replaced; however, this item is being tracked
. by the licensee as an open work item on the Master Tracking System and is scheduled for completion prior to fuel loa Staff Position 21.
This allegation was not substantiated in that the licensee did appropriately document the occurance and does plan to replace the affected nozzle.
This allegation is closed.
~Ai R
i d
The licensee's replacement of the nozzle will be followed up as a
part of the routine inspection program.
Licensee Event Re ort LER Followu
- Units 1 and
a 0 The following LERs associated with operating events were reviewed by the inspector.
Based on the information provided in the report it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below listed LERs are considered closed.
Unit 2 LER NUMBER DESCRIPTION LER 86-32-00 Missed Fire Watch Due to Personnel Error 22.
No violations of NRC requirements or deviations were identified.
Followu of IE Bulletin 85-01:
Steam Bindin of Auxiliar Feedwater AFW Pum s - Unit 3.
This Bulletin discusses the potential for AFW pumps to become inoperable as a result of steam binding.
The actions taken by the licensee in response to this bulletin have been reviewed previously in Inspection Report 528/86-20 for Unit I and 529/86-20 for Unit 2.
The actions taken involved the installation of temperature sensitive tape on the discharge pipe of the "N" pump; a revision to procedures requiring shiftly monitoring of the pipe temperature; and, the development of a procedure for recovery from a steam binding event should it occur.
During this inspection, the inspector verified the installation of the temperature sensitive tape on the discharge piping of the "N" pump in Unit 3 and reviewed the Unit 3 specific procedures implementing the licensee preventive and recovery actions for a steam binding event.
The actions taken by the licensee were formally communicated to the NRC as requested in the bulletin.
The licensee's response indicated that the "A" and "B" safety related pumps are not considered to be susceptible to steam binding due to the existence of two normally closed valves plus three check valves on each pump discharge line
'hich isolate main feedwater from the pumps, and therefore nc specific actions have been taken with respect to these pumps.
Based
Yp li
on the licensee's response and the specific actions taken in Unit 3, this Bulletin is closed for Unit 3.
23.
No violations of NRC requirements or deviations were ide'ntified.
Followu of Generic Letter 85-05: Inadvertent Boron Dilution Events
- Unst 3.
The purpose of this letter was to inform each licensee of operating pressurized water reactors of the staff position resulting from the evaluations of Generic Issue 22, "Inadvertent Boron Dilution Events," regarding the need for upgrading the instrumentation for detection of boron dilution events.
The letter contained no requirements or.actions, ot)er than an urging of each licensee to assure themselves that adequate protection against boron dilution events was in effect at their plants.
The actions taken by the licensee in response to this letter have been reviewed previously in Inspection Report 528/85-21 for Unit I and 529/85-22 for Unit 2.
A boron dilution alarm from the startup range nuclear instrumentation is being used by the licensee to provide alarm indication for a I/3 of a decade increase in shutdown neutron level.
The inspector verified that procedures which addressed a boron dilution accident were available in Unit 3, and through discussion with several operators of the required actions upon a possible inadvertent boron dilution alarm, verified that the operators have been trained in the use of these procedures.
This item is closed for Unit 3.
24.
No violations of NRC requirements or deviations were identified.
Review of Periodic and S ecial Re orts - Units 1 and
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 require-ments; 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 I o
Monthly Operating Report for December, 1986.
Unit 2 o
Monthly Operating Report for December, 198 ~c.
l
No violations of NRC requirements or deviations were identified.
25.
~Ei The inspector met with licensee management representativps period-ically during the inspection and held an exit on Febroary 19, 1987.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed and acknowledged by the licensee representative hg