IR 05000387/1985036
| ML17146A277 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 02/19/1986 |
| From: | Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17146A275 | List: |
| References | |
| 50-387-85-36, 50-388-85-32, NUDOCS 8602250268 | |
| Download: ML17146A277 (33) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-387/85-36 50-388/85-32 Docket Nos.
50-387 CAT C 50-388 CAT C
License Nos.
NPF-14 NPF-22 Licensee:
Penns lvania Power and Li ht Com an 2 North Ninth Street Allentown Penn s 1 vani a 18101 Facility Name:
Sus uehanna Steam Electric Station Inspect'ion At:
Salem Townshi Penns lvania Inspection Conducted:
December
1985 Februar
1986 Inspectors:
R.
H. Jacobs, Senior Resident Inspector L.
Pli o,
esident Inspector Approved By:
J.
trosnider, Chief, Reactor Projects Section 1B, DRP Ins ection Summar z/yg/pe date
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of plant operations, licensee events, open items, Part 21 reports, ESF system walkdown, plant modification program, surveillance, and maintenance.
Results:
The inspector noted that Unit 2 RHR loops were unknowingly cross-connected while in Condition 3 (Detail 2. 1);
ESF walkdown of CREOASS system identified procedural and labeling deficiencies (Detail 2.3); operability determination of frozen spray network was based on an invalid Technical Speci-fication determination (Detail 3.3); outage planning and modifications review noted that the planning and preparations for the Unit 1 second refueling outage are comprehensive and that DCPs reviewed were thorough and complete (Detail 7.0).
One violation was identified for not testing CREOASS dampers (Detail 5.2).
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DETAILS 1.0 Followu on Previous Ins ection Items Closed Ins ector Followu Item 388/85-17-02
- Reactor Protection S stem Rela s
In June 1985, the inspector identified that HFA relay maintenance recommendations from Service Information Letter (SIL) No.
44 Supple-ment 4 were not being performed during maintenance on HFA relays in the reactor protection system (RPS).
In addition, no consideration was being given to performing time response testing following main-tenance on the K-14 scram relays.
The inspector also expressed a
concern that some RPS relay maintenance had not received gC coverage.
"
1.2 In response, the licensee issued procedure MT-GE-025, Revision 0,
"GE HFA Relay Contact Maintenance",
dated October 1,
1985.
The procedure includes the recommendations from SIL No.
44 Supplement 4 concerning HFA relay contact wipe, gap and pick up voltage check and adjustment.
Procedure AD-gA-502, Work Authorization System, was revised and Main-tenance Instruction, MI-PS-006,
"Maintenance Planners Guide for Post-Maintenance Response Time Testing for Electrical Circuits" was developed to provide guidelines for performing response time testing following maintenance on safety related instruments'he inspector reviewed the above documents and identified no discrepancies.
Since this oc-currence, the inspector has observed that the SIL No.
44 recommenda-tions have been included in RPS relay maintenance and that complete gC coverage has been provided.
Closed Violation 387/84-22-04
- Failure to Perform Re uired Surveillance Testin on Fire Detection Instrumentation in Twelve Fire Zones In July 1984, the inspector identified that between September 23, 1983 and July 5, 1984, each of the required instruments in at least twelve fire zones were not demonstrated operable by the performance of a channel functional test as required by Technical Specification Table 3.3.7.9-1.
Upon identification of the overdue and incomplete surveillance tests, the licensee performed the semi-annual functional test of the ioniza-tion detectors.
The tests were completed satisfactorily on July 6, 1984.
The licensee conducted a review of all fire detection zones affected by the same procedure and no further discrepancies were identifie q,, t
To prevent recurrence, the licensee conducted a review of the sur-veillancee tests for all types of fire detectors in all fire detection zones specified in the Technical Specifications for both units'o other discrepancies were identified.
In addition, administrative procedure AD-(A-422, Surveillance Testing Program, Revision 6, states that partial surveillance tests are not considered completed survei 1-lance activities in the surveillance activity scheduling system, and that partial tests shall only be used for special testing, activities.
The inspector reviewed the revised procedures and found them acceptable.
Closed Ins ector Followu Item 388/84-33-01:
Procedural Deficiencies Noted Durin Core S ra Walkdown In September 1984, the inspector identified several minor procedural deficiencies associated with the Unit 2 Core Spray System during a
walkdown of the system.
The licensee corrected the noted deficien-cies in check-off lists CL-251-012 and CL-251-015.
The inspector reviewed the revised procedures and verified completion of the corrective action.
~Closed Ios actor Fol 1owu Item 388/85-21-01:
Reactor Scr am Durin Surveillance Testin In August 1985,"the Unit 2 reactor scrammed due to an IKC technician error during surveillance testing on reactor vessel water level in-struments.
During the licensee's post-trip review, several possible corrective actions concerning the performance of surveillance proce-dures were identified to prevent recurrence of this type of event.
Although the surveillance procedure, SI-245-201, was found to contain no errors or misleading steps, the procedure was revi sed.
The procedure revision incorporated a confirmation step for correct water level configuration at two independent locations and now requires the test signal to be injected at the instrument rack in lieu of the relay room.
This allows use of the level instrument "in service" lights which are controlled at the instrument rack.
The event was also reviewed with IKC personnel during training.
The inspector verified the above corrective actions.
Closed Unresolved Item 388/84-27-01:
IRM/SRM Overla Verification During Unit 2 startup testing, the inspector noted that IRM/SRM overlap did not indicate a one decade overlap with the SRM's fully inserted.
The data met the acceptance criteria of at least one-half decade overlap.
The inspector's concern was based on FSAR Figure 7.6-14 which indicated a full decade of overlap.
The licensee has determined in conjunction with GE, that overlap is dependent on the individual sensor sensitivity.
The only requirement is for a
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one-half decade overlap, as stated in the Technical Specifications.
The licensee intends to revise the FSAR to clarify this point.
The inspector had no further concerns.
Closed Ins ector Followu Item 387/85-28-01:
Deficiencies in Technical S ecifications Concernin Containment Isolation Valves In September 1985, the inspector identified several discrepancies in the Technical Specifications concerning primary containment isolation valves.
The discrepancies required a change to Technical Specification Table 3.6.3-1 for both Units.
On December 26, 1985 proposed Amendment 76 to NPF-14 and Amendment 31 to NPF-22 were submitted to NRR (PLA-2576).
The proposed amend-ment included the necessary administrative changes to accurately reflect the as-built configuration of the containment isolation system.
The appropriate surveillance testing is already being conducted on the isolation valves.
Closed Ins ector Followu Item 387/83-25-04
- Unresolved Test Exce tion Re orts Test Exception Reports (TERs) 404, 433, 23 and 395 remained unresolved following completion of the Unit 1 startup test program.
These TERs have been resolved as follows:
TERs 404 and 433 concerned flow coastdown for the recirculation pumps being outside the acceptance criteria.
The interim action taken by the licensee was to take the Minimum Critical Power Ratio (MCPR) penalty for EOC - Recirculation Pump Trip (RPT) inoperable.
During Cycle 2, in the Susquehanna Unit 1 Cycle 2 Plant Transient Analysis (XN-NF-84-118), the actual reciculation pump coastdown data was used as input to the transient model, and will be in future reloads.
TER 23 concerned the Rod Position Indication System (RPIS) not providing a continuous display on the CRT four rod display during rod movement.
The TER was resolved by memo dated November 28, 1983 from the IKC Supervisor.
The CRT display will occasionally not display rod position during continuous rod movement if timing is off between RPIS and computer interface cards'he standby information panel four rod display does provide continuous indication.
The CRT display will display valid rod position after the rod stops.
This condition is understood by the operators.
TER 395 concerned abnormal oscillatory behavior of the 'B'eactor Feed Pump (RFP) flow and turbine speed signals during five inch level changes.
The TER was resolved by performing a retest following feed-water control tuneup after the first, refueling outage.
The retest indicated acceptable feed pump response to five inch level change.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciators was rev'iewed.
Nuclear Instrument panels and other reactor protection systems were examined.
Effluent monitors were reviewed for indications of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability.
During entry to and egress from the protected area, the inspector observed access control, security boundary integrity, search activities, escorting and badging, and availability of radiation monitoring equipment.
The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection period.
Sampling reviews were made of tagging requests, night orders, the bypass log, Significant Operating Occurrence Reports (SOORs),
and gA nonconformance reports.
The inspector observed several shift turnovers during the period.
During a control room tour on January 16, Unit 2 was in Operational Condition 3, Hot Shutdown, at approximately 55 psig pressure.
The licensee was warming the '8'HR system in preparation for placing RHR in shutdown cooling.
The inspector noted that both RHR crosstie valves, F010A and 8, were open.
The procedure, OP-249-002,
"RHR Operation in the Shutdown Cooling Mode", step 3. 1.4.f specified re-storing power to and opening crosstie valve F010A or 8, (depending upon which loop will be put in shutdown cooling) to enable discharging RHR water to the condenser hotwell via the crosstie piping.
The op-erator apparently misread the procedure and restored power to and opened both the F010A and 8 valves, thereby cross-connecting both RHR loops.
This condition is prohibited by Technical Specification 3.5. 1 which is applicable in Operational Conditions 1,
2 and 3.
The action statement specifies that with no crosstie valve closed or with power not removed, be in Hot Shutdown in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Cold Shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
This cross-connected condition only existed for several minutes, so the action statement was not exceeded.
The in-spector discussed this situation with the affected operator.
The operator immediately shut the F010A valve to split the RHR loops and had power removed from the valve.
The operator indicated that this was the first time he had placed the RHR system in shutdown cooling and that he had misread the procedur The inspector noted that the procedure was opened to the appropriate section and that the operator was referring to it as he performed the procedure steps.
The inspector discussed this occurrence with the Station Superintendent.
This incident is considered to be an isolated occurrence and will not be further pursued.
No other unacceptable conditions were identified.
2.2 Station Tours The inspector toured accessible areas of the plant including the control room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, diesel generator building, ESSW pumphouse, and the plant perimeter.
During these tours;= observations were made relative to equipment condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
2.2. 1 MSIV Solenoid Manifold Assembl Environmental During a tour of the Unit 2 Reactor Building on January 6,
1986, the inspector noted Nonconformance Tag NCR 85-0153 posted outside the Unit 2 Main Steam lunnel.
The associated Nonconformance Report (NCR), issued March 14, 1985, stated that the MSIV solenoid manifold assemblies were not in compliance with the environmental qualification requirements of 10 CFR 50.49.
The report also stated that in order to be fully qualified, the two-way, three-way, and four-way valves mounted on the manifold must be disassembled to change out the seal lubricant from Parker Super-0-Lube to Houghton SAFE 620.
In addition, the mounting screws for the solenoid NEMA-4 box were to be checked fully tightened.
The MSIV actuator control manifold vendor is Automatic Valve Corporation.
The disposition of the NCR, approved on April 8, 1985, required the seal lubricant to be replaced and a check performed on the tightness of the NEMA-4 box.
Work Authorization (WA) V53350 was written to perform the work and is currently scheduled for the first refueling outage.
This same condition exists for the Unit 1 assemblies and is documented on NCR 85-0354.
WA-S54098 is to be performed during the Unit 1 second refueling outag '1 l'
The NCR's were written following completion of environ-mental qualification testing of the MSIV solenoid manifold assemblies by Wyle Laboratory in January 1985.
The test results indicated that the solenoid valves with Parker Super-0-Lube did not operate properly following the radia-tion testing.
Data collected by Wyle indicated that when exposed to a radiation field of greater than 1 x 10E6 RAD, the Parker Super-0-Lube lubricant breaks down into an ad-hesive, powdery substance which could adhere to the moving parts of the actuator and restrict or prevent solenoid valve movement.
The operation of the MSIV assembly is such that the solenoid valve directs air to the valve actuator to open the MSIV and vents air from the actuator to close the MSIV.
The safety concern was that the lubricant break-down may prevent the MSIV from closing when required.
When the NCR was written, the licensee composed an internal justification for operability.
The document stated that the accumulated radiation exposure would not reach the breakdown threshold (1 x 10E6 RAD) prior to the next re-fueling outage (for each Unit), when the corrective main-tenance would be performed.
The radiation field to which these solenoids are subjected is given-as
R/HR for the inboard MSIV's and 5 R/HR for the outboard MSIV's.
The fields are listed in FSAR Table 3. 11-6.
Rough calculations show that the seal lubricant is adequate for greater than 800 days of full power operation.
In addition, the licensee stated that under actual accident conditions, the MSIV solenoids would be deenergized prior to experiencing the radiation level necessary to cause lubricant breakdown.
The FSAR states that the LOCA dose rate could reach 1.4 x 10E7 RADS/HR.
The mounting screw tightness was judged not to be a significant concern since failure of the mounting screws resulted in a fail-safe condition.
The inspector questioned the licensee concerning the quali-fication status of the manifold assembly since the NCR stated the manifolds were not qualified, the NCR corrective action had not been completed, and the NCR remained open.
The licensee submitted a letter dated November 27, 1985 (PLA-2563) to the NRC stating that the plant had completed final environmental qualification in accordance with the requirements of 10 CFR 50.49.
Further discussions with the licensee on January 7 and
.determined that they considered the solenoid manifold assemblies environmentally qualified and that the wording
of the NCR, was not fully correct.
The corrective action involving the seal lubricant is only required to extend the qualified life of the manifold and the MSIV's will operate as designed until the next refueling outage.
The Unit 1 seals were last replaced on May 23, 1985 and the Unit 2 replacements were performed on December 11, 1984.
The inspector also reviewed the Eg binder for the solenoid manifolds on January 22, and no discrepancies were identified.
The inspector had no further questions.
2.3 ESF S stem Walkdown 2.3.1 Control Room Emer enc Outside Air Su
S stem On January 8,
1986, the inspector independently verified the operability of the Control Room Emergency Outside Air Supply System (CREOASS)
by performing a walkdown of accessible portions of the system.
The engineered safety feature status verification included the following:
Confirmation that the system checkoff list and operating procedure are consistent with the plant drawings and as-built configuration, Identification of equipment conditions and items that might degrade performance, Identification of properly functioning instrumentation while the system was operating, Verification that valves and breakers were properly aligned.
The following references were used for this review:
Technical Specifications FSAR Sections 6.4, 6.5, and 9.4 Drawing VC-178, Revision 19, HVAC Control Diagram Control Structure Schematic Diagrams HVAC, E-197, Sheets 1-12 OP-030-002, Revision 4, Control Structure HVAC Unit of Instruction, SY017-L-ll, Revision 0, Licensed Operator System Control Structure HVAC
The following items were identified during this review:
The positions of several CREOASS dampers are not checked in the operating procedure or checkoff list (COL).
Dampers not checked include HD-07811A/B, HD-07812A/B, and HD-07814A/B.
The actuation of these dampers after an automatic actuation signal is checked, but the pre-actuation position and/or power available should be verified in the alignment for automatic operation.
No root valves for CREOASS instrumentation are included in the COL.
The licensee has a program to label and include all instrument root valves in the checkoff lists and CREOASS root valves will be included in this program.
Power supplies for the Division I and II LOCA, radiation and chlorine actuation logic are not verified in the COL.
Labeling of components in the CREOASS system is inadequate.
There is virtually no permanent labeling of system components or instrument root valves.
The licensee is conducting a major plant relabeling program, which will include these components.
Drawing VC-178 incorrectly shows dampers HD-07802A and HD-07802B, which are in series in the outside air inlet ducting, in reverse order.
The licensee is initiating a change to this drawing.
The SBGTS HVAC system is required for operability of CREOASS components, and hence, it should be included in the prerequisites section of 3.4 of OP-030-002.
The inspector will review licensee's corrective action on the above discrepancies.
(387/85-36-01)
3.0 Summar of 0 eratin Events 3.1 Unit 1 Unit 1 operated at or near 100 percent power for most of the inspection period.
Scheduled power reductions were conducted throughout the period for control rod pattern adjustments and surveillance testin.2
.Unit 2 At 2:37 p.m.
on January 15, 1986 the Unit 2 reactor was manually scrammed following a power reduction to 70 percent.
The shutdown was initiated by observation of oil spraying out of the 'B'hase main transformer.
Oil samples taken following the scram indicated the transformer was not damaged; The cause was loss of power to the transformer cooling pumps and fans when one of the fans shorted out.
During the forced outage repairs were performed on the 'A'ransformer which had been showing signs of excessive gassing and a leaking RCIC isolation valve inside containment.
Unit 2 returned to criticality at 4: 11 a.m.
on January 21.
At 8: 19 a.m.
on January 21, the Unit 2 reactor scrammed from
percent reactor power on reactor vessel low level due to operator error.
Level decreased during the startup due to an open bypass valve and feeding of the vessel was not initiated in time to prevent a trip.
The unit returned to criticality at 6: 10 p.m. the same day.
Following power escalation, the unit, operated at or near full power for the remainder of the period.
3.3 Ultimate Heat Sink S ra Network Frozen On December 21, 1985 at 7:30 p.m. ice blockage was identified in the B2 Emergency Service Water Spray Network while attempting to blowdown the networks.
The frozen spray network was caused by a leaking butterfly isolation valve which allowed water to fillup the spray network header and risers.
Ice plugging occurred when the networks were being blown out periodically with air during extreme weather conditions.
The occurrence was determined to be not reportable by the licensee based on an internal Technical Specification interpretation on Spray Pond operability issued on January 24, 1984 (PLI-30636).
The interpretation stated that the spray pond could be considered operable with no spray networks available assuming an initial spray pond temperature of less than 42 degrees F.
Since the spray pond temperature was approximately 35 degrees F., the system was not declared inoperable.
On December 23, 1985 the inspector discussed the event with the con-trol room operators and noted that another paragraph in the interpre-tation stated that all four arrays were required to be operable for two Unit operation.
This statement appeared to contradict the pre-vious operability determination.
Further review determined that the satisfactory condition of 42 degrees F. spray pond temperature with no spray networks was based on an assumption of Unit 1 in Operational Condition 4 and Unit 2 defueled.
The previous analysis did not apply to the current condition with both units at full powe II <
Several previous occurrences of frozen spray networks have been identified.
On January 6,
1984 the licensee identified that the spray pond loop 'B'pray distribution network was incapable of performing its safety function when the spray network froze and
spray distribution arms decoupled and fell into the pond due to accumulated ice (LER 84-002).
This was reviewed in Inspection Reports 50-387/83-29 and 50-388/84-07.
On March 19, 1984, during the performance of weekly spray piping drain pump operations implemented as corrective action to the January event, it was determined that the Al and B2 spray networks were inoperable due to apparent ice plugs (LER 84-017).
Unit 1 was in Operational Condition 4 at the time of both events.
The inspector and Region I management expressed concern with the potential for this degraded condition to exist when the spray networks are requ'ired to be operable, and the'refore included a
license condition for Unit 2 to submit an acceptable long term solution to the freezing problem by September 1,
1984.
The licensee submitted their proposed solution to Region I on August 31, 1984 (PLA-2232).
The short term solutions proposed to be completed by the end of 1984 included installation of self-priming array draindown pumps and level detection devices.
The long term corrective action included an auto-start feature for the draindown pumps scheduled to be installed by the end of 1985.
Several operational problems have been encountered with the level detection devices, but they cannot be corrected until the weather permits filling the spray risers. 'he risers are currently being pumped down manually.
The short term modifications were completed January 5,
1985 and were reviewed in Inspection Report 50-387/85-09 and the open item was closed.
The Technical Specifications do not clearly specify the operability requirements for the spray network arrays.
LCO 3.7. 1.3 states that the spray pond shall be operable.
The associated surveillance requirements only verify the water temperature and level.
The RHRSW LCO and ESW LCO only require an operable flow path.
The FSAR (Section 9.2.7) states that the spray pond will meet the performance requi rements of an ultimate heat sink under a LOCA/Forced Shutdown combination with only one spray network (i.e.
one loop) operable.
Several areas of concern were identified during this event.
First, the operability determination was made by the control room operators based on an invalid Technical Specification Interpretation.
Although inspector review of the data found that no LCO was violated, the conclusion was reached by the operators with an incorrect assumption.
The station has developed a procedure to issue approved Technical Specification Interpretations, but it has not been fully implemented.
The second concern is that there is currently no written guidance to the operators concerning the operability requirements of the spray pond networks with both units in operation, and apparently some guidance is needed.
Similar
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concerns were expressed-in Inspection Report 50-387/85-18 since specific guidance does not exist concerning the ESM alignment to the diesel generators to prevent a single failure susceptibility.
This concern will be reviewed under open item 387/85-18-01.
Diesel Generator Crankcase Ex losion On January 18, 1986, during surveillance testing (SO-024-013) of Emergency Diesel Generator
"B", a crankcase overpressurization occurred.
The surveillance was being performed prior to taking the T-10 startup transformer out of service for maintenance.
The diesel had been unloaded for two minutes following a fifteen minute run.
A Nuclear Plant Operator (NPO) was in the diesel bay and manually tripped the engine using the local emergency stop button when he heard abnormal noises and saw smoke.
Fire alarms actuated in the control room, but no diesel unit protective alarms were evident.
The overpressurization lifted all of the crankcase explosion covers, relieving the pressure to the area around the engine.
Oil was found on the bay floor and walls.
The fire brigade was activated, bu't was not required.
No personnel were injured.
The diesel was declared inoperable in accordance with Technical Specification 3.8.1.1.
Licensee inspection found excessive scoring, heat discoloration and damage (metal displacement)
to the cylinder number 5L piston, rings, wrist pin, and cylinder liner.
On January 21, 1986, repairs were completed and the diesel was tested according to the vendor's (Cooper-Bessemer)
recommendations.
After post-repair surveillance testing was completed satisfactorily, the "B" diesel engine was declared operable.
Licensee investigation during disassembly of 'the damaged components found that the piston pin bolts were only finger tight and the bolt locking device was "mushroomed".
If the bolts had been loose, the oil flow to the piston pin (wrist pin) could have been interrupted, causing failure of the piston pin.
The resident inspectors inspected the damaged components and observed the diesel repair s.
A previous crankcase explosion occurred in January 1984 (see Inspection Report 50-387/83-29; 50-388/83-32)
on the "D" Diesel Generator and was attributed to fuel oil contamination of the lube oil.
The lowered viscosity of the lube oil by dilution with fuel oil caused the oil film to not be sufficient to carry the load on the pin.
The vendor stated, following the 1984 failure, that the pi ston pin and articulated rod pins are probably the most critical bushings in the engine and, if lubrication was questionable, it would probably be the first component to fai I'
V II
During the repairs the licensee checked the tightness of all the other left bank piston pin bolts, and all were found tightened to the required torque.
During modification work in the "A" diesel generator on January 26-27, all of the bolts were checked and found satisfactory.
3.5 Radioactive S ills in Radwaste and Turbine Bui ldin s
At 2:00 p.m.
on January
a spill of approximately 1000 gallons occurred in the common Radwaste building on the 646 foot elevation.
The spill occurred when the "C" and "D" Liquid Radwaste Collection Tanks overflowed after pumping water from the Turbine Building outer area sump.
The collection tanks were in the recirculation mode when the operators noted an increasing level in the Radwaste Building sump.
The spi'll covered approximately 4000 square feet of floor area.
Average contamination levels were 20,000 DPM/100cm~.
No personnel contaminations or offsite releases occurred.
The licensee issued a press release and made an ENS notification.
The area was roped off and cleaned up.
The overflow of the tank was caused by a faulty tank level detector.
At 3:50 a.m.
on February 1,
a spill of approximately 3500 gallons occurred in the turbine building when a gasket blew out of a vent line flange on the 1E condensate demineralizer vessel.
Unit 2 was at full power, steady state, and there was no work in progress on the demineralizer vessel, when the spill occurred.
The spill covered approximately 250 square feet, primarily in the 'E'nd
'D'emineralizer rooms with some water in the 676 foot elevation hallway.
Operations reduced power to about 80 percent and removed the 'E'emineralizer from service.
The spill stopped when the demineralizer was isolated.
Most of the water drained down the room floor drains.
There were some small accumulations of resin.
Average contamination levels were 180 mRad per 100 cmz.
There was no personnel contamination and no offsite release occurred.
The licensee issued a press release, although no ENS notification was made.
The licensee installed a compressed fibrous gasket in the flange and returned the vessel to service.
A similar spill on the 1B condensate demineralizer occurred on October 26, 1985.
The source of this spill was also from the
1/4-inch vent line flange, due to a blown gasket.
The gasket material used in both of these occurrences was red rubber which was not the specified material for this application, but a material which the licensee determined to be suitable.
The flange gaskets had been replaced on the lE vessel on January 14, 1986.
As 'a precaution on February 4, the licensee replaced the 'A'ent line flange gasket (a red rubber gasket which had been in place only since January 24) with a compressed fibrous gasket.
There are still red rubber gaskets in three of the seven condensate demineralizer
vessel vent line flanges on Unit 1.
The licensee intends to rework these flanges and the manway covers to ensure all have the proper material, prior to the end of the second refueling outage, which is scheduled to begin February 15.
A similar program is planned for Unit 2.
4.0 Licensee Re orts 4. 1 In-Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit
- 85-034, Unit 1 and Unit 2 Reactor Scram Due to Loss of ESS Transformer 111 85-035, Transfer of Bus 10 Loads to Bus 20 Due to 230KV Transmission System Fault Unit 2 None this period.
~Previously discussed in Inspection Report 50-387/85-35; 50-388/85-31 4.2 Review of Periodic Re ort Upon receipt, periodic reports submitted by the licensee were reviewed by the inspector.
The report was reviewed to determine that the report included the required information; that test results and/or supporting information were consistent with design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems, and whether any information in the report should be classified as an abnormal occurrence.
The following periodic report was reviewed:
Monthly Operating Report - December 1985, dated January 15, 1986.
The above report was found acceptabl.3 Part
Re orts On December 23, 1985 a preliminary
CFR 21 notification was received by the NRC from Applied Engineering Corporation (AEC).
The notification stated that air start receiver tanks for the Fifth Diesel Generator Project were deficient.
Calculations for two six-inch inspection nozzles had not been performed as required by Section III of the ASME Code and that the inspection opening was not adequately reinforced for present design conditions.
It also stated that the attachment welds for the opening were undersized for the design conditions.
On the same day, the inspector discussed the notification with licensee representatives.
The licensee stated that they had been informed of the deficiency by the vendor and were "pursuing corrective action to adequately reinforce the inspection nozzles.
This notification only affected the Fifth Diesel Generator which is still under construction.
On February 4,
a Region I inspector contacted the gA manager of AEC and was informed of the following.
The design work of ASME III components was limited to these air receivers and hence, it is not a
generic problem.
AEC was using a "new" engineer to perform this work, not the design engineer who usually performs ASME III code work.
A drawing change and a plan to add reinforcement for the nozzles have been submitted to Morrison Knudson for review (AEC was under contract to Morrison Knudson for this work).
The design pressure of the air receivers is 275 psig.
They had been hydrostatically tested to 422 psig.
The calculated maximum design pressure as fabricated is 232 psig.
The 422 psig hydro-test was more than six percent over code allowable excess pressure in test, but engineering review by AEC indicated that no overstressing occurred.
The Part 21 report remains open pending completion of corrective action.
(387/85-36-02)
5.0 Monthl Surveillance and Maintenance Observation 5.1 Surveillance Activities The inspector observed the performance of surveillance tests to determine that: the surveillance test procedure conformed to technical specification requirements; administrative approvals and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequenc tj
'I
These observations included:
S0-151-002, quarterly Core Spray Flow Verification, performed on January 15, 1986.
TP-024-031, PMR 83-812B Retest, performed on the 'A'/G on
'anuary 29, 1986.
No unacceptable conditions were noted.
5.2 Surveillance Procedure Review The inspector conducted a review of surveillance procedures and surveillance test results associated with the Control Room Emergency Outside Air Supply System (CREOASS).
The review was conducted to ascertain whether the survei llances are performed in accordance with approved procedures and that the procedures correctly implement Technical Specification requirements.
The following items were reviewed:
Technical Specifica'tion 4.7'.
FSAR Section 6.4 and 6.5.
S0-030-002, Revision 1,
18 Month Control Structure Ventilation System Operabi lty Test, and test results dated February 5,
1984 and August 12, 1985.
SI-030-201, Revision 1, Monthly Channel Functional Test'of the Chlorine Detecto'r Channels XISH-07802A/B.
SI-030-301, Revision 1,
18 Month Detector Functional Test of the Chlorine Detector Channels XISH-07802A/B, and test results dated December 19, 1984.
SE-030-010, Revision 0, Radionuclide Penetration and Retention Test for CREOASS Charcoal Assembly, and test results dated January 31, 1985.
S0-030-001, Revision 1, Monthly CREOASS Operability Test.
SE-030-009, Revision 0, CREOASS HEPA Filter and Charcoal Absorber In-Place Leak Test, and test results dated January 17, 1985.
With the exception of S0-030-002, no discrepancies were identified in this revie SO-030-002 implements Technical Specification (TS) requirements 4.7.2.d.2, 3 and 4.
Technical Specification 4 ' '.d.2 specifies that, once per 18 months, on receipt of an isolation actuation test signal, the subsystem automatically switches to the isolation mode and the isolation dampers close within 8 seconds.
The isolation actuation test signals are 1) outside air high chlorine, 2) outside air high radiation and 3) Reactor Building isolation.
The following discrepancies were noted with SO-030-002:
a)
Isolation dampers HD-07814A/B, HD-07812A/B and HD-07833A/B iso-late on a high chlorine signal, but the damper position and timing are not verified by SO-030-002.
The licensee indicated HD-07833A/B, control room relief fan dampers, are caution tagged closed and never opened.
Dampers HD-07814A/B and HD-07812A/B, are normally closed CREOASS fan inlet dampers and have not been tested in accordance with the Technical Specification require-ment since at least February 1984.
Failure to test these dampers is a violation (387/85-36-03).
In response, the licensee de-clared both CREOASS systems inoperable on January 10, 1986, and tested the dampers.
All four dampers isolated in less than one second.
b)
To satisfy the above 8 second timing requirement, the licensee verifies that the dampers shut in 8 seconds by observing the indicating lights.
FSAR Table 6.4-1 indicates that the damper closure times are 3 seconds and that the total time between a
chlorine detector signal generation and closure of the isolation dampers is 8 seconds.
SO-030-002 does not measure the time between generation of the high chlorine signal and start of damper closure.
c)
Dampers HD-07824Al and B1 are not verified closed and timed when the high radiation and Reactor Building isolation signals are tested.
They are checked on the high chlorine signal.
The licensee is changing the 18 month functional surveillance tests from SOs, which are Operations survei llances, to SEs which are Technical Staff survei llances.
The SO-030-002 is scheduled to be rewritten and reissued as an SE prior to the next performance.
The procedure will be reviewed when issued.
(387/85-36-04)
5.3 Maintenance Activities The inspector observed portions of selected maintenance activities to determine that: the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes, or standards.
The following items were considered during this review:
Limiting Conditions for Operation were met while components or sys'tems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished
using approved procedures and gC hold points were established where required; functional testing was performed prior to declaring the particular component operable; activities were accomplished by quali-fied personnel; radiological controls were implemented; fire protec-tion controls were implemented; and the equipment was verified to be properly returned to service.
Activities observed included:
Repairs of the "B" Diesel Generator 5L cylinder on January
and 20, 1986 under WA S63131.
Checking of piston pin bolt torque on the "A" Diesel Generator on January 27, 1986 under WA S63156.
Repairs to the "B'hlorine Detector on January 16, 1986 under WA S66099.
No unacceptable conditions were noted.
6.0 Unit 1 Potential Reload Analysis Problem The licensee informed the residents on January 10 that during Unit 1 Cycle 2 (present cycle) Operation, the fuel design and operational limits for Exxon fuel are not adequate to ensure that the fuel remains below the 1%
plastic strain limit during certain anticipated operational occurrences (AOO).
The core has a mix of GE and Exxon fuel.
The GE limit to ensure the fuel remains below 1% plastic strain, is Average Planar Linear Heat Generation Rate (APLHGR) which ensures that the Linear Heat Generation Rate (LHGR) limit (14.5 KW/ft for Exxon) is not exceeded.
Under low flow, relatively high power conditions, the licensee has determined that a re-circulation pump runout could cause the plastic strain limit to be exceed-ed on some fuel nodes, even though the pre-transient APLHGR limit was not exceeded.
This condition is prevented on GE fuel by requiring T (T =
Fraction of Rated Power (FRP) divided by the Maximum Fraction of Limiting Power Density, MFLPD) to always be less than or equal to 1.0.
For Exxon fuel, T is defined to be equal to 1.0.
At present, there is disagreement between PP5L and Exxon concerning the need for a limit on T for Exxon fuel.
The licensee discussed this with NRR the week of January 13.
In the Cycle 3 reload Technical Specification request dated January 16, 1986, the li-censee is including a limit on T and LHGR for Exxon fuel.
In the interim, the licensee has modified plant procedures to check that the Fuel Design Limit Ratio for Exxon fuel (equivalent to MFLPD) is always less than or equal to FRP, for the remainder of Cycle 2 (which ends February 15, 1986).
The inspector reviewed procedure change 1-86-0012, to surveillance. proce-dure SR-100-001 Revision 2, and verified that the above interim measure is in effec l~
IIV rl
7.0 Unit 1 Second Refuelin Outa e and Modifications Review 7.-1 Outa e Overview Briefin In the Systematic Assessment of Licensee Performance (SALP) Report No. 50-387/85-99; 50-388/85-99 dated July 15, 1985, NRC Region I man-agement listed several recommendations concerning Outage Management and Modification Activities.
The report requested the licensee to meet with NRC.Region I to discuss outage planning prior to refueling outages.
It also stated inspections would be conducted of engineering support effort at the corporate office prior to the refueling outage.
The Unit 1 Second Refeling Outage is scheduled to commence February 15, 1986.
On January 21-22, 1986 an inspection of the design change and modification program was conducted at the Allentown, Pennsylvania corporate offices.
A meeting was conducted on January 21 to provide a general overview of the outage, the modifications to be installed, invessel inspection plans, the modification process, licensing commit-ments, common system controls, and post-modification testing.
Licensee's planning and preparation for this outage is very comprehen-sive.
Virtually all modification and implementation packages have been prepared and the majority of maintenance work packages have been planned.
7.2 Im lementation of Plant Modification Pro ram The implementation of the Plant Modification Program was reviewed at the corporate office to verify the following:
Changes were reviewed and approved in accordance with 10 CFR 50.59 and Technical Specifications, and the technical content of the safety evaluations was satisfactory.
As-built drawings were changed to accurately reflect the modification.
Independent design verification was adequately performed and documented.
Applicable documents were updated to reflect the modification (i.e
~ procedures, vendor manuals, Technical Specifications, and FSAR).
Adequate post-modification testing was identified to be performe Documentation of calculations and analyses were included or referenced in the modification package.
Adherence to NDI and EPM procedures.
The following Design Change Packages (DCPs) were reviewed and discussions were held with several of the responsible engineers:
DCP 83-0746 DCP 84-3088 DCP 84-3113 DCP 84-3117C DCP 85-3068 DCP 85-3071 DCP 85-3073 DCP 85-3097A DCP, 85-3099C DC P 85-3100A Nitrogen Makeup System Modification Replace Hand Switch in RHR System Modify Degraded Grid Voltage Protection SPDS Enhancements RCIC Pump Discharge Check Valve HPCI Pump Discharge Check Valve HPCI Lube Oil Ball Valves ATWS Modification Standby Liquid Control System Steam Dryer Instrumentation Removal ATWS - Alternate Rod Insertion Findings:
l.
In general, the noted DCPs were thorough and comprehensive.
Documentation was adequate to address all of the above attri-butes.
No discrepancies were noted in the content of the packages.
DCP 84-3088 adds a
new handswitch to the F003 A/B valves, RHR heat exchanger outlet valves, to enable throttling the valves under low heat load conditions while in shutdown cooling.
The valves are 20-inch Anchor Darling gates valves which are not normally designed for throttling.
The inspector reviewed PP5L calculation M-RHR-011 dated July 18, 1985 which verified that the differential pressure across the valve would be low (less than 2 psid).
An assumption in the calculations is that the heat exchanger bypass valve, F048 A/B is open, and hence most flow would bypass the heat exchanger.
The calculation indicates that, on the basis of the low differential pressure across the valve, the vendor indicated that the valve could be throttled with no restriction.
No calculations were performed to indicate whether the differential pressures across the F003 A/B with F048 A/B fully closed, were acceptable to permit unrestricted throttling of F003.
The inspector, during review of TP-149-026
"Retest for PMR 84-3088 (Division I)", noted that F048 is throttled fully closed, while F003 is 20 percent open with an initial flow rate of 10,000 gpm in the suppression pool cooling mode of RHR.
This condition is outside the design development of analyzed valve performance.
The licensee agreed to revise this procedure and TP-149-027, which tests Division II.
Since this modification is not installed, the test has not yet been performe.
DCP 85-3097A performs the mechanical portion of an ATWS modification to the Standby Liquid Control (SLC) System.
This DCP, among other things, adds separate suction piping from the SLC storage tank to the 'A'ump (there is presently a
common suction line for both pumps).
The inspector noted that the new suction line design did not include a temperature element (TE)
such as is provided on the present common line.
This TE provides an alarm in the control room if there is a loss of suction piping heat tracing and is discussed on FSAR page 9.3-30.
There was no reference in the DCP concerning the need for this TE nor was the licensee able to provide an adequate explanation, before the end of the inspection period, for not including the TE and alarm on the new suction piping.
Licensees actions on items 2 and 3 above will be further reviewed.
(387/85-36-05)
8.0 MSIV Local Leak Rate Testin
'n the Susquehanna Safety Evaluation Report dated April 1981, the licensee has an exemption from 10 CFR 50 Appendix J to permit conducting local leak rate testing (LLRT) of the MSIVs by pressurizing between the inboard and outboard valves.
The exemption, which is referenced in Technical Specification 3.6. 1.2, specifies conducting the test at 22.5 psig (one-half containment design basis pressure),
due to the concern of lifting the inboard valve off its seat since it is being pressurized in the non-accident direction.
The licensee has since procured high pressure rated main steam line plugs which will now permit testing at containment design basis pressure (i.e.
45 psig) in the desired direction.
Since the exemption is still in effect, the licensee requested clarification on whether NRC review and approval was required to permit testing in accordance with the method which does not require the exemption.
The inspector discussed this issue with NRR on January 24.
NRR indicated that it is permissible to perform the testing as specified in Appendix J or as specified in the exemption without further NRR review.
9.0 Safet Committee Activit On January 23, 1986, the inspector attended a meeting of the Susquehanna Review Committee (SRC), which is the offsite safety review committee for Susquehanna, in corporate headquarters.
The meeting was attended by all eleven members and consisted of presentations on various safety topics by members or other PP&L staff, followed by discussions by committee members.
In the inspector's view, the topics reviewed were relevant and important to plant safety.
Among the topics reviewed were:
1) recent plant scrams and other operational events, 2) safety review of the upcoming Unit 1 second refueling outage, and 3) diesel generator reliability modifications.
The inspector identified no concerns during the meeting and will review the meeting minutes when issue ~ 7 r
l
1
.0 ~Ei
.Il On February 10, 1986 the inspector discussed the findings of this inspec-tion with station management.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to 10 CFR 2.790 restrictions.