IR 05000275/1991010
| ML16341G124 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 05/31/1991 |
| From: | Morrill P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341G123 | List: |
| References | |
| 50-275-91-10, 50-323-91-10, IEB-88-004, IEB-88-4, NUDOCS 9106180117 | |
| Download: ML16341G124 (34) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION REGION V
Report Nos:
50-275/91-10 and 50-323/91-10 Docket Nos:
50-275 and 50-323 License Nos:*
Pacific Gas and Electric Company 77 Beale Street, Room 1451 San Francisco, California 94106 Facility Name:
Diablo Canyon Units 1 and
Inspection at:
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
March 17 through April 27, 1991 Inspectors:
P.
P. Narbut, Senior Resident Inspector K. E. Johnston, Resident Inspector Approved by:
P. J. Morri 1, Chief, Reactor Projects Section
Date Signe Summary:
Inspection from tiarch 17 throug~hA ril 27, 1991, (Re ort Nos. 50-275/91-10 and 50-323/91-10T Areas Inspected:
The inspection included routine inspections of plant operations, maintenance and surveillance activities, follow-up of onsite events, open items, and licensee event reports (LERs),
as well as selected independent inspection activities.
Inspection Procedures 60710, 61726, 62703, 71707, 90712, 92700, 92701, and 92702 were used as guidance during this inspection.
e Safety Issues Mana ement S stem (SIMS) Items:
None Results:
General Conclusions The inspectors noted the following general weaknesses; o
Inadequate communications between design engineering and the plant apparently resulted in two instances where equipment that did not meet design requi rements was installed in the plant.
910bl80l l7 9l053l PDR ADOCN 05000275 Q
PDA
-2-As discussed in paragraph 4.e, an auxiliary feedwater pump motor was installed without required environmental qualification reviews.
As discussed in paragraph 4.f, a residual heat removal check valve, manufactured to operate in horizontal piping, was installed in vertical piping.
o Documentation of operability determinations continued to be a
problem (paragraph 4.g).
The April 10, 1991 rationale for the operability of the Unit 1 motor driven auxiliary feedwater pumps was not documented and was apparently incomplete.
Operability of the motors was questioned when both fuel handling building supply fans, which cool the auxiliary feedwater pump rooms, became inoperable.,
o There appeared to be a lack of ownership for completed plant modifications (paragraph 5.a).
Following the completion of the boron injection tank bypass modification, the inspector observed a
considerable amount of debris left at the job site.
Neither the craft involved nor the system
"design sponsor" appeared to have responsibility for final area cleanup and restoration of the system to its as-found condition.
Summer of Violations and Deviations".
None 0 en Items Summar:
Five LER reviews were completed and two followup items were opene DETAILS Persons Contacted J.
D.
D. B.
- N. J.
- B. W.
D. K.
W. G.
W.
D.
T. A.
D. A.
- T. L.
K. J.
J.
S.
W.
G.
J.
A.
N.
G.
S.
R.
R.
E.
C.
Townsend, Vice President, Diablo Canyon Operations 5 Plant Manager Niklush, Manager, Operations Services Angus, Manager, Technical Services Giffin, Manager, Maintenance Services Oatley, Manager, Support Services Crockett, Assistant Plant Mianager, Support Services Barkhuff, guality Control Manager Bennett, Mechanical Maintenance Manager Taggert, Director guality Support Grebel, Regulatory Compliance, Supervisor Phillips, Electrical Maintenance Manager Bard, Planning Manager Crockett, Instrumentation and Controls Manager
'houlders, Onsite Project Engineering Group Manager Burgess, System Engineering Manager Fridley, Operations Manager Gray, Radiation Protection Manager Connell, Assistant Project Engineer The inspectors interviewed several other licensee employees including shift forem'en (SFYi), reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, quality assurance personnel and general constructionfstartup personnel.
- Denotes those attending the exit interview.
D~ils<<
ibl c r ill<<d2 At the start of the inspection period, Unit 1 was in cold shutdown following the completion of refueling activities.
Unit 1 was paralleled to the grid on April 4, 1991.
A reactor trip occurred on April 22, 1991 as a result of a feedwater transient initiated by the failure of a feedwater pump
~
A manual reactor trip was initiated during startup on April 24, 1991 after the loss of manual control of the control rods due to a rod control system urgent failure.
Unit 2 was at full power for the duration of the period, except for brief periods where power was reduced to facilitate maintenance.
Operational Sa~fet Verification~71707)
General During the inspection period, the inspectors observed and examined activities to verify the operational safety of the licensee's facility.
The observations and examinations of those activities were conducted on a daily, weekly or monthly basis.
On a daily basis, the inspectors observed control room activities to verify compliance with -selected Limiting Conditions for Operations (LCOs)
as prescribed in the facility Technical Specifications (TS).
Logs, instrumentation, recorder traces, and other operational records were examined to obtain information on plant conditions and to evaluate trends.
This operational information was then evaluated to determine if regulatory requirements were satisfied.
Shift turnovers were observed on a sample basis to verify that all pertinent information of plant status was relayed to the oncoming crew.
During each week, the inspectors toured the accessible areas of the facility to observe the following:
(a)
General plant and equipment conditions.
(b)
Fire hazards and fire fighting equipment.
(c)
Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures.
(d)
Interiors, of electrical and control panels.
(e)
Plant housekeeping and cleanliness.
(f)
Engineered safety feature equipment alignment and conditions.
(g)
Storage of pressurized gas bottles.
The inspectors talked with operators in the control room, and other plant personnel.
The discussions centered on pertinent topics of general plant conditions, procedures, security, training, and other aspects of the work activities.
Radiolocaical Protection The inspectors periodically observed radioloaical protection practices to determine whether the licensee's program was being implemented in conformance with facility policies.and procedures and in compliance with regulatory requirements.
The inspectors verified that health physics supervisors and professionals conducted frequent plant tours to observe activities in progress and were aware of significant plant activities, particularly those related to radiological conditions and/or challenges.
ALAPA considerations were found to be an integral part of each RWP (Radiation Work Permit).
C.
Security activities were observed for conformance with regulatory requirements, implementation of the site security plan, and.
administrative procedures including vehicle and personnel access screening, personnel badging, site security force manning, compensatory measures, and protected and vital area integrity.
Exterior lighting was checked during backshift inspections.
No violations or deviations were identifie.
Onsite Event Follow-u 93702$
a e Diesel Generator 1-2 Slow Start On March 18, 1991, diesel generator (DG) 1-2 was declared inoperable after it failed to load to its vital bus within the time required by the Technical Specifications (TS) during the performance of a surveillance test.
DG 1-2 took approximately nineteen seconds vice the ten seconds required by TS 4.8. 1. 1.2.
Unit 1 was in a refueling outage with DGs 1-1 and 1-3 operable.
On April 17, 1991, the licensee issued Special Report 91-03, documenting the test failure.
The licensee determined that a first level undervoltage relay functioned intermittently and caused a delay in the loading of the DG to its vital bus.
The root cause of the intermittent operation of the relay was not determined.
The relay was sent to the licensee's testing facility for failure analysis.
At the close of the inspection period, the failure analysis had not been completed.
The inspectors will follow the resolution of this 'item through the routine review of non-conformance reports.
The special report identified the failure to load within the specified time as a non-valid failure as defined by TS Table 4.8-1.
This determination was questioned by the Electrical Distribution System Inspection and will be discussed in Inspection Report 50-275/91-07.
b.
Unit 2 Letdown Line Crack~inn A pears Resolved On March 19, 1991, Operations reported a fine mist spraying out of a Unit 2 chemical and volume control system (CVCS) letdown line elbow, upstream of orifice isolation valve 8149C.
The line was isolated and repairs initiated.
In addition to a leaking elbow weld, six damaged pipe supports were found.
This was the fifth Unit 2 letdown line leak since June 1989.
i During the repair effort, the licensee apparently determined the cause of the letdown line failures.
The "C" letdown orifice was removed and inspected.
The letdown orifices are one foot long, two inch diameter, stainless steel cylinders with a 1/4 inch aperture through the center.
The discharge end of the C orifice was severely pitted, resulting in a 3/4 inch opening, reducing to the nominal 1/4 inches at a depth of 1 1/4 inches.
The licensee's root cause determination indicated that the damaged orifice was causing flow induced vibration.
The vibration was causing welds to fai 1 and, in the last event, was causing pipe support damage.
The licensee's review concluded that the damage to the orifice had occurred when pressure downstream of the orifice was reduced below the pressure required to prevent cavitation at the orifice
J f
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discharge.
This pressure reduction and resulting cavitation had occurred for the following reasons:
1)
For several months in 1989, an out of calibration pressure transmitter (PT 135) provided a false. input to a pressure regulating valve (PCV 135).
As a result, unknown to the operators, the downstream pressure was reduced.
2)
A pressure relief valve on the downstream side had a
misadjusted blowdown setting.
During several events between 1987 and 1989, the relief valve lifted and remained open for an extended period of time.
3)
The licensee postulated that once the orifice was damaged, self induced cavitation further damaged the orifice.
A new orifice was placed in service.
The line vibration was reduced by a factor of ten and was comparable to the vibration at the "B" orifice, which was out of service.
During the refueling outage, the licensee inspected the three Unit
letdown flow orifices and found them to be in satisfactory condition.
The licensee has taken the Unit 2 "B" orifice out of service and plans to replace it during the next refueling outage.-
The Unit 2 "A" orifice (the seldom used
gpm orifice) will be inspected for damage.
This problem has been discussed in several inspection reports and is the subject of Open Item 50-323/90-31-01.
Further NRC review will be performed of the licensee's analysis.
On March 23, 1991, with Unit 1 in cold shutdown following refueling, an unplanned start of DG 1-1 and a realignment of safety injection valves occurred when a non-licensed operator inadvertently actuated the wrong solid state protection system (SSPS)
test switch.
This event was determined by the licensee to be a reportable engineered safety features (ESF) actuation.
The control room operators subsequently returned all actuated equipment to normal status and made a four-hour, non-emergency report.
During a routine test of the SSPS, the operator inadvertently actuated the wrong test switch (S-816 vs. S-817).
The licensee determined that the operator had failed to implement policies and procedures regarding concurrent verification and self-verification.
As corrective action, the licensee issued an incident summary (requi red reading for operations personnel)
reemphas'izing the importance of the self-verification process and reviewing the requirements and content of the concurrent verification proces e
"P
This event was the subject of Licensee Event Report 50-275/91-05, issued April 19, 1991.
The inspector found the LER to be acceptable.
Unit 1 Containment Ventilation Isolation On March 26, 1991, with Unit 1 in cold shutdown following refueling activities, a containment ventilation isolation actuation occurred.
The actuation occurred due to a high radiation alarm from the containment air particulate monitor (RM-ll).
The licensee determined that the event was an ESF actuation and made a four-hour, non emergency report to the NRC.
The licensee determined that when the RN-ll sample pump seized, causing its motor to fault, radio frequency interference (RFI) was produced.
The RFI induced a high radiation signal at RM-11.
As corrective action, the licensee planned to implement a design change to provide thermal overload protection for the sample pump motor to prevent locked rotor current from continuing for a duration sufficient to short the motor's insulation.
Additionally, the licensee plans to upgrade the radiation monitoring system.
One of the reasons for the upgrade was to reduce the sensitivity of the radiation monitoring system to RFI.
On April 25, 1991, the licensee submitted LER 50-275/91-06.
The inspector found the LER to be acceptable.
1
2 1 1 f1
f 2 ~ifi
.'~fl-2 On March 28, 1991, the licensee's Plant Safety Review Committee (PSRC)
approved a "Justification for Continued Operation" addressing the failure to provide appropriate environmental qualification (Eg) for the Auxiliary Feedwater Pump (AFWP) 1-2 motor, replaced during the refueling outage (JCO 91-03).
The inspector found the JCO to be acceptable.
However, the replacement of the motor without appropriate Eg review indicated a weakness in the communications between engineering and the plant.
A commercial grade replacement AFWP motor was purchased in 1986 and stored in the warehouse.
In 1987, a Replacement Part Evaluation (RPE)
was completed to allow dedication of this motor for use in safety related service in a mild environment.-
The AFWP motors were not determined to be in a harsh environment requiring Eg unti 1 1989 when a recalculation of the environmental conditions in the AFWP rooms was performed.
It was determined in 1989, when environmental conditions were recalculated using refined methodology, that the room could reach 128 degrees F and 100%
humidity during a design basis event.
The manufacturer provided an analysis showinq that the installed motors could withstand the environmen N
Due to a communications failure, the new Eg requirements were not specified for the motor in the warehouse.
During the Unit 1 refueling outage, the AFWP motor was installed under the 1987 RPE.
The failure to include the current Eg requirements for the installation of the AFWP motor was considered a non-conformance and included in an existing NCR regarding other recent failures to provide acceptable Eg for plant components (NCR DC0-90-EN-N017).
The resolution of this NCR will be evaluated during routine inspection activities.
Residual Heat Removal Pump Check Valve On March 28, 1991, the licensee discovered that a check valve installed at the discharge of Residual Heat Removal (RHR) heat exchanger (HX) 1-2 would not close as designed.
It was discovered that a check valve, designed to be installed in a horizontal run of piping, had been installed in a v'ertical run.
The licensee issued a
JCO to address the failure of the valve to operate for the current cycle.
The inspector found the JCO to be acceptable.
However, this appears to be another example of weak communications between design engineering and procurement.
Check valves were installed at the discharge of the Unit
RHR HXs during the Unit 1 refueling outage.
The check valves wer e installed in response to NRC Information Bulletin 88-04, "Parallel Operation
.of Safety-Related Pumps."
Bulletin 88-04 identified a concern with pump to pump interaction during miniflow operation which could result in the dead-heading of one of the pumps.
The licensee determined in 1988 that the RHR pumps were susceptible to this condition.
As an intermediate step, and the basis for JCO 88-03, a
change to emergency operation procedures was made to have operators shutdown an RHR pump if the pumps were operating while reactor coolant system pressure was above the pump shut off head.
The =long term action was to install check valves at the HX discharge.
The most recent JCO (JCO 88-03, Revision 3) concluded that there was no difference in the consequences of a check valve which failed to operate and not having a check valve installed.
The inspector observed that there was the potential that the check valve was not performing its function because it had become disassembled.
Although there was substantial subjective evidence, the original JCO referenced no physical evidence that the check. valve was hung up vice disassembled.
Following a discussion of this issue, the licensee performed a radiograph which confirmed the check valve was not disassembled.
A non-conformance report was initiated to determine how a check valve designed for installation in a horizontal pipe was installed in a vertical pipe (NCR DC1-91-EN-N016).
The inspector will review the resolution of the NCR during routine review of NCR e
0 erabilit of the Notor Driven Auxiliar Feedwater Pum s With nopera e
ue an inq us sn ents at>on u
ans On the evening of'April 10, 1991, the Unit 1 auxiliary feedwater system (AFWS) was considered operable even. though the fuel handling building's ventilation system (FHBVS) supply fans were both inoperable.
The FHBVS supply fans provide room cooling necessary for operation of the two motor driven AFMPs.
The shift supervisor had briefly discussed with the system engineering manager the impact of the inoperable FHBVS supply fans on the AFWS and concluded that the AFMS was operable.
The basis for this decision was not documented and it is not clear that. this decision was made with appropriate consideration of the AFWS design basis.
'The inspector had the following concerns; 1)
Did the licensee take the appropr'iate actions to determine operability.
2)
Has the licensee, recognizing that there was little information available to make a timely operability decision, taken appropriate corrective action.
3)
Was the AFWS operable with the FHBVS supply fans inoperable.
The Initial 0 erabi lit Determination With one FHBVS supply fan out of service for maintenance, the second supply fan tripped and could not be restarted.
The operation shift supervisor recognized that the fans supplied room cooling for the AFMS.
However, no readily available plant information addressed the effects of two inoperable FHBYS supply fans on the operability of the AFWS.
The shift supervisor contacted the system engineering manager by phone regarding the operability of the AFWS.
The two concurred that there was no immediate operability concern.
The inspector interviewed the system engineering manager who indicated that the operability determination was based on the following:
1)
The room was cool, well below the technical specification limit of 103 degrees F.
2)
Room temperature monitors would provide control room annunication of temperatures greater than 103 degrees-F, allowing operators to take compensatory measures such as opening doors.
3)
The system engineering manager had been involved in a recent evaluation of AFWP room temperatures to support an Eg evaluation for the AFWP motors.
Based on his knowledge of this evaluation, he concluded that in the worst case conditions,
there was sufficient margin to prevent the pump motors from.
overheating.
,.The decision, but not its basis, was documented in the shift foreman's logs.
The inspector had the following concerns; 2)
The basis for the operability determination was not documented.
a As discussed below, it was not apparent that the operability determination was soundly based.
3)
There was no procedure or policy discussing how to perform the operability determination nor how the determination should be documented.
,Had both AFWS motor driven pumps been declared inoperable, Technical Specification 3.7. 1.2 would have required a shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Licensee's Evaluation of the 0 erabilit Determination The discussion above indicates that the licensee has had continuing problems making operability determinations when operability is not readily apparent.
Similar problems were identified with the operability determination for 1-FCV-95 ( Inspection Report 50-275/90-30).
In response to the findings regarding 1-FCV-95, the licensee committed to establish a formal procedure for operability determinations.
The licensee had not completed this process when the April 10, 1991 question regarding the operability of the AFWS was raised.
The inspector discussed the need to provide an interim process for operators to use until a formal process is developed.
The plant manager committed that the basis for future operability determinations will be documented and committed to pursue the timely completion of the formal operability evaluation procedure.
The licensee has scheduled completion of this procedure for June 1991.
Accn~rac of the Licensee's O~erabilit~netermination In addition to the operability determination performed on April 10, 1991, a documented operability evaluation was completed on April 18, 1991.
At the end of the inspection period, a question regarding the operability evaluation was being addressed by design engineering.
The April 18, 1991 operability analysis assumed a worst case room temperature based on the existing room temperatures and the postulated heat loads from three operating AFWPs.
The inspector addressed the following questions to design engineering; 1)
Why was the auxiliary steam header, located in the turbine driven AFMP room, not assumed to fail as it was in the E(}
analysis for the AFWP motor e
2)
Was the successful operation of the FHBVS supply fans assumed in the EQ analysis as appears to be indicated in the body of NCR DC0-89-N020.
3)
Was the EQ analysis for the AFWP motors valid with inoperable FHBVS supply fans.
This item is open pending the resolution of the above questions (Unresolved Item 50-275/91-10-01).
Unit 1 Hi h Steam Generator Level Turbine Tri and Subse uent On April 23, 1991, with Unit 1 reactor power at approximately 50%,
a high steam generator level turbine trip and subsequent reactor trip occurred.
The event was preceded by an attempt to recover from the loss of a main feedwater pump at IDOLS power.
During the reactor trip recovery, an excessive cooldown rate was observed and operators closed the main steam isolation valves (NSIV).
The plant was subsequently stabilized in hot standby using the atmospheric steam dump valves to control decay heat.
Both resident inspectors observed the reactor trip from the control room.
A four hour non-emergency report was made to the NRC in accordance with 10 CFR 50.72.
Prior to the event, feedwater regulating valve FCV-530, which had control problems, was in manual control with bypass valve FCV 1530 in automatic.
At 8:34 a.m.
on April 23, main feedwater pump (NFP)
1-1 began to rapidly pick up load.
In automatic response, NFP 1-2 dropped load.
In response, operators began to ramp the plant to 50K power.
NFP l-l subsequently tripped on what was determined later to be high pump discharge pressure.
In response to the transient, the digital feedwater control system (DFMCS) controlled the feedwater regulating valves.
However, when FCV-1530 had completely closed, the DFMCS placed it in manual control.
With FCV-530 in its 100% power position, steam generator 1-3 was overfed.
Although operators attempted to stabilize steam generator levels once 50% power was reached, steam generator 1-3 high level was reached at 8:46 a.m., resulting in the unit trip.
At 8:48 a.m.,
a low pressurizer pressure annunciator alarmed, indicating an excessive cooldown rate.
The flSIVs were closed in accordance with emergency operations procedures.
The reactor coolant system had reached 1950 psi and 530 degrees F.
The plant was subsequently stabilized using the atmospheric steam dump valves.
The licensee determined that the NFP 1-1 control system had failed due to the fai lure of a logic card.
Additionally, the transient was exacerbated by having FCV-530 in manual.
Following the upgrade of the feedwater control system, Unit 2 had previously withstood a loss of feedwater pump event from 100K power with all controls in automati V
~
~
~
~
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2)
Was the successful operation of the FHBYS supply fans assumed in the EQ analysis as appears to be indicated in the body of NCR DC0-89-N020.
3)
Was the EQ analysis for the AFWP motors valid with inoperable FHBVS supply fans.
This item is open pending the resolution of the above questions (Unresolved Item 50-275/91-10-01).
U~iitlihS G
L 1T bi Ti dEb Reactor Tr>
On April 23, 1991, with Unit 1 reactor power at approximately 50%,
a high steam generator level turbine trip and subsequent reactor trip occurred.
The event was preceded by an attempt to recover from the loss of a main feedwater pump at 100% power.
During the reactor trip recovery, an excessive cooldown rate was observed and operators closed the main steam isolation valves (MSIY).
The plant was subsequently stabilized in hot standby using the atmospheric steam dump valves to control decay heat.
Both resident inspectors observed the reactor trip from the control room.
A four hour non-emergency report was made to the NRC in accordance with 10 CFR 50.72.
Prior to the event, feedwater regulating valve FCV-530, which had control problems, was in manual control with bypass valve FCV 1530 in automatic.
At 8;34 a.m.
on April 23, main feedwater, pump (MFP) l-l began to rapidly pick up load.
In automatic response, MFP 1-2 dropped load.
In response, operators began to ramp the plant to 50K power.
MFP 1-1 subsequently tripped on what was determined later to be high pump discharge pressure.
In response to the transient, the digital feedwater control system (DFWCS) controlled the feedwater regulating valves.
However, when FCV-1530 had completely closed, the DFWCS placed it in manual control.
With FCV-530 in its 100% power position, steam generator 1-3 was overfed.
Although operators attempted to stabilize steam generator levels once 50% power was reached, steam generator 1-3 high level was reached at 8:46 a.m., resulting in the unit trip.
At 8:48 a.m.,
a low pressurizer pressure annunciator alarmed, indicating an excessive cooldown rate.
The MSIVs were closed in accordance with emergency operations procedures.
The reactor coolant system had reached 1950 psi and 530 degrees F.
The plant was subsequently stabilized using the atmospheric steam dump valves.
The licensee determined that the MFP l-l control system had failed due to the failure of a logic card.
Additionally, the transient was exacerbated by having FCV-530 in manual.
Following the upgrade of the feedwater control system, Unit 2 had previously withstood a loss of feedwater pump event from 100K power with all controls in automati The excessive cooldown rate was caused by the failure of a condenser steam dump valve.
As had been noted on three previous occasions, the valve stem had separated inside the valve body and the valve plug became lodged in a partially open position.
The repeated failure of steam dump valves is discussed in detail in paragraph 5.b of this report.
The licensee will submit an LER on this event.
Followup of tHe licensee's event evaluation corrective actions will be accomplished during the review of the L'ER.
Unit 1 Manual Reactor Tri Followin Failure of Control Rod Control S~stem On April 24, 1991, with Unit 1 reactor power at 2.5X and increasing, plant operators initiated a manual reactor trip following a failure of the control rod control system.
All systems functioned as designed and a four hour non-emergency report was made to the NRC.
Operators had just completed zero power physics testing and were in the process of raising control rods to establish a start.up rate of 0.5 decades per minute when a control rod control system urgent failure alarm was received and prohibited control rod movement (as designed).
Operators attempted to determine the cause of the failure and attempted to move the control banks individually to no avail.
When reactor power reached two percent and an apparent positive moderator temperature coefficient indicated that power would not stabilize, the shift foreman ordered the plant to be tripped.
Electricians determined that a fuse in a rod control cabinet had blown. It was later determined that this fuse and several others in the same cabinet were a model which should have previously been replaced.
This older model fuse had been p~one to fail'ure during routine operation due to a manufacturing problem.
Although a work order and material request indicated that new style fuses had been procured and installed, this had not been successfully accomplished.
At the end of the inspection period, the licensee was investigating the fuse replacement problem.
An LER was scheduled to be submitted for the event.
The inspectors will review the root cause evaluation and corrective actions during the review of the LER.
No violations or deviations were identified.
5.
Maintenance (62703 The inspectors observed portions of, and reviewed records on, selected maintenance activities to assure compliance with approved procedures, technical specifications, and appropriate industry codes and standards.
Furthermore, the inspectors verified maintenance activities were performed by qualified personnel, in accordance with fire protection and housekeeping controls, and replacement parts were appropriately certifie a.
Boron Injection Tank B
ass DesiBn~Chan e
The inspector noted unfinished work in a modification and found the probable cause to be a lack of ownership.
The inspector examined portions of the completed modification design change; the bypass of the boron injection,tank (BIT).
The BIT has been abandoned in place.
The charging piping which had passed through the BIT had been cut and a
new bypass section of piping was added.
The inspector noted the following deficient conditions on April 25, 1991.
The Unit 1 piping was in service.
The insulation and heat tracing had been removed since it was no longer required.
However, metallic tape and tape residue had been left on the old pipe.
This condition is probably not detrimental and is a
case of poor job completion workmanship.
The licensee was asked to verify the tape and residue were not harmful to stainless steel pipe.
On the new piping, the liquid penetrant developer had not been thoroughly removed from 'new piping'welds.
The licensee was asked to verify the developer was not harmful to stainless steel pipe.
o Boric acid buildup was evident near valve SI-1-8906, on mechanical fittings, and on valve SI-1-4 on a socket weld.
The licensee was asked to investigate to determine whether a weld leak had occurred.
o There was a metal sheath on the charging piping for about
inches under vent valve SI-1-4.
The material appears to be insulation canning material which is not shown on the modification drawing.
It appeared to be an effort to keep
.
boron from valve SI-1-4 from dripping on the pipe.
The licensee was asked why this sheath was installed.
The inspector identified the findings to operations supervision on shift and followed up with licensee management the following day.
The licensee responded to the findings as.follows; o
The heat tracing tape residue was left over from original installation.
The licensee determined that the tape did not chemically effect the integrity of the piping.
o The dye penetrant, if left permanently, would not chemically damage the piping.
o The boric acid leak near Sl-1-8906 had been previously identified and was being tracked under the licensee's boric acid leak identification program.
The licensee did not find boric acid near SI-1-The inspectors noted that it was difficult to identify any primary responsibility for the inspector's findings.
All agreed that construction forces should have done a better cleanup job, but it was difficult to establish which licensee organization should have found, identified, and elevated the problems for resolution.
The licensee has a variety of walkdowns by operators, management, and quality control, which apparently did not note the problems.
The main administrative control for modification completion is the
"design sponsor" program at Diablo Canyon.
A single individual is charged with the responsibility to ensure a modification is properly completed.
In this case, according to the assistant plant manager for technical services, the design sponsor was not aware that he was responsible for final workmanship.
He only took responsibility for the satisfactory completion of essential operability aspects.
The APM for technical services agreed to consider actions for improvement in the design sponsor's role.
The inspectors consider the aspects of unfinished work in the BIT room to be an example of problems with work ownership at Diablo Canyon.
This was discussed with licensee management at )he exit interview.
Condenser Steam Dump Failures Six Unit 1 condenser steam dumps have recently experienced stem failures.
1-PCV-1 failed following a reactor trip on December 24,
.
1990 (see inspection report 50-275/90-30).
1-PCV-6 and 1-PCV-7 failed during restart testing (March 30 and April 2, 1991, respectively).
1-PCV-2 failed during the April 23, 1991 reactor trip (see section 4.h).
1-PCV-1 and 1-PCV-11 failed on May 17, 1991, following a reactor trip (this event will be discussed in more detail in Inspection Report 50-275/91-13).
The steam dump failures, which occurred following reactor trips, resulted in high cooldown rates requiring operator action to mitigate the consequences.
As a result of the failures during March restart testing, the licensee formed a task force to investigate the failures.
The licensee prepared a Justification for Continued Operation (JCO 91-04)
on April 2, 1991 and initiated a non-conformance report (NCR DC1-90-TI-N091).
Discussions regarding the failures of the steam dump valves, the cause of failures and the potential effects on plant operations, were held between the Region V office and the licensee staff on April 2, April 24, May 17, 18, and 19, 1991.
The steam dump valves are manufactured by Copes-Vulcan.
The valves are eight inch, air operated, reverse acting, globe valves with internal pilot valves.
At the end of the inspection period the licensee had had three analyzed to determine the failure mode.
In
each instance the failure appeared to be an overload of the stem inside the valve.
i The licensee's preliminary conclusions of the failure mode was as follows:
The valve main plug microwelds to the valve main seat.
The seating surfaces of the plug and valve body are ground to set up a "line contact" seating surface and are of the same material.
The contact area is very narrow (approximately 3 thousandths of an inch).
The seating surfaces (both made of 410 stainless steel)
microweld after being in contact under pressure.
When called on to open, the air operator will continue to build up pressure until the seating surfaces separate.
The plug then accelerates under the built up force until the actuator hits its bottom stop.
The impact momentum of the plug creates a tension force on the stem, which separates at its weakest point.
At the end of the inspection period it was not clear to the NRC staff that microwelding was occurring or could occur.
Additionally, it was not clear why this commonly used valve design was.failing at Diablo Canyon, and not at other sites.
The inspectors will followup the licensee's evaluation in a future inspection (Open Item 50-275/91-10-02).
No violations or deviations were identified.
6.
Surveillance (61726 Sy direct observation and record review of selected surveillance testing, the inspectors assured compliance with TS requirements and plant procedures.
The inspectors verified that test equipment was calibrated, and acceptance criteria were met or appropriately dispositioned.
II The inspector observed and reviewed aspects of the inservice testing of a Unit 2 component cooling water pump.
No violations or deviations were identified.
7.
Open Item Follow-up (92703, 92702)
Concrete S allin (0 en Item 50-275/91-03, 0 en)
During the inspection period, the inspector identified concrete spalling in the following areas; 1)
The sumps at the ASW discharge end of the component cooling water heat exchangers.
Although the heat exchangers are in the turbine building, the sumps are exposed to saltwater from the ASW system.
2)
The pedestal for the circulating water pump discharge isolation valv The licensee was notified of these findings and determined that there were no immediate safety consequences.
Concrete spalling occurs when saltwater seeps through the outer layer of concrete and corrodes the rebar.
The corroded rebar expands and breaks or damages the outer layer of concrete.
The licensee identified concrete spalling in the following areas; 1)
A horizontal ceiling beam in the intake area, 2)
A support pedestal for a Unit 2 CCW heat exchanger.
The licensee determined that these findings had no immediate safety consequences.
During a meeting between the resident inspector and the PG&E Acting Project Engineer and members of his staff, the licensee presented a
schedule to determine the extent of spalling concrete in areas inaccessible during plant operations (e.g.
the ceiling and walls of the intake bays).
The licensee will perform the inspections during the upcoming refueling outages.
This item remains open.
8.
Licensee Event Re orts The LERs identified below were reviewed and followup inspection was performed.
The LERs were found to be acceptable.
Unit 1:
89-09 Revision 1, 91-05, 91-06 Unit 2:
90-09 Revision
9.
Exit (30~703 On May 30, 1991 an exit meeting was conducted with the licensee's representatives identified in paragraph 1.
The inspectors summarized the scope and findings of the inspection as described in this report.