IR 05000373/1986035

Insp Repts 50-373/86-35 & 50-374/86-36 on 860903-1007. Violation Noted:On 860916 Reactor Not in at Least Hot Shutdown & PWR Svc Water Temp Indicator on Remote Shutdown Panel Inoperable 7 Days After Indicator Made Inoperable

ML20213D164
Person / Time
Site:	LaSalle
Issue date:	10/23/1986
From:	Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20213D150	List: IR 05000373/1986035 ML20213D149 ML20213D160
References
50-373-86-35, 50-374-86-36, NUDOCS 8611100448
Download: ML20213D164 (13)

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U.-S. NUCLEAR REGULATORY ~C0P941SSION

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REGION III

.v Reports-Noi~ 50-373/86035(DRP); 50-374/86036(DRP)

4, fDo'cket Nos: 50-373; 50-374 Licenses No. NPF-11; NPF-18 Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690

-Facility Name: LaSalle County Station, Units 1 and'2

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Inspection At: LaSalle Site, Marseilles, IL t Inspection Conducted: September 3 through October 7, 1986'

Inspectors

M.' J. Jordan

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J.-Bjorgen i

R.'Kopriva-

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J. Mueller l

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! J."Ulie

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Approved By:./

G t ,( /0[83 Ob j R eactor Projects Section 2C Date

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Inspection Summary Inspection on September 3 through October 7, 1986 (Reports No. 50-373/86035(DRP);

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Areas Inspected: . Routine, unannounced inspection conducted by resident inspectors of licensee' actions on previous inspection findings; operational safety; surveillance; maintenance;. training; Licensee Event Reports; temporary L instruction TI 2515/82; TMI action plan requirement followup; regional requests; Part 21 followup; unit trips; and refueling / outag . Results: The licensee's performance during the startup.of Unit I was very good. The testing of equipment before startup to assure operability of safety

as well as balance of plant equipment was very effective in minimizing the i- amount of equipment failures and problems after.startup. The overall '

L performance of the station during the startup was considered very good.

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8611100448 861029 PDR ADOCK 05000373 G PDR

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DETAILS

'1. ' Persons Contacted

• G. J. Diederich', Manager, LaSalle Station

• R. D. Bishop, Services Superintendent

• J. C. Renwick, Production Superintendent D. Berkman, Assistant Superintendent, Work Planning

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• Huntington, Assistant Superintendent, Operations

• P. Manning, Assistant Superintendent, Technical Services

• T. Hammerich, Assistant Technical Staff Supervisor W. Sheldon, Assistant Superintendent, Maintenance J. Atchley, Operating Engineer

• R. W. Stobert, Qu'ality Assurance Supervisor

• Denotes personnel attending the exit interview on October 7, 198 . Licensee Action on Previous Inspection Findings (92701)

(Closed) Open Item (374/86020-04(DRP)): The licensee was to take action to improve the shiftly logs. The licensee has initiated a corrective action plan which included input from the unit operators and other shift personnel as well as increased attention by operations management. The improved quality of log keeping has been noted.by the inspectors such that this item may be' close (Closed) Open Item (373/83049-02(DRP)): The licensee was to install temperature monitoring instrumentation in the shutdown cooling system suction piping. This installation was completed during the first refueling outage by Modification 1-1-84-06 (Closed)OpenItem(373/84002-16(DRP)): The licensee was to evaluate needed replacement for non safety related cables in~ the Unit 1 drywell subjected to high temperatures. The licensee replaced the Integrated ,

Leak Rate Test cables above the 777' level and tested and inspected the other cables of concern and found no degradation requiring repai (Closed)OpenItem.(373/84026-04(DRP)): The licensee was to correct a discrepancy between the terminal block wire identifications and the terminal block numbers for the "C" vacuum breaker. Work Request L42627 was completed on the "C" vacuum breaker, and the other vacuum breakers were inspected. No additional problems were identifie (Closed) Open Item (374/86020-03(DRP)): Licensee was to clarify the duties of the independent verifier during control rod manipulations with reactor thermal power at or below 20% of rated power and the Rod Worth Minimizer inoperable. The inspector reviewed the clarifying revisions to procedures LGP 1-1, 1-2, 1-3, 2-1, and 2-2 and found them adequate. This item is considered close __ . - _ . . . -_. - - .-

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(Closed) Open Item (373/84002-11(DRP)): The licensee was to replace cables spliced at junction boxes due to heat damage. These cables were replaced by Work Request L36106 during the first refueling outag (Closed) Open Item (373/84002-13(DRP)): The licensee was to evaluate the-remaining life of heat damaged cables and replace as necessary. The licensee inspected cables during the first refueling outage, found no degradation, and incorporated the results into the EQ binders. All cables were determined to have a full 40 years remaining useful lif Future inspections are scheduled in accordance with the normal EQ binders-inspection (Closed) Open Item (373/84002-15(DRP)): The licensee was to evaluate equipment other than cabling subjected to high temperatures in the drywell. The licensee completed this evaluation and incorporated the results into the EQ~ binders and general surveillance progra (Closed) Open' Item (373/81-00-120(DRP)): This open item tracked Unit 1 OperatingLicenseCondition2.C(25)(c). This condition required that prior to startup after the first refueling outage, the licensee provide fire-protection systems in fire areas 2C/3C, 4C3, and 6E. The inspector verified that fire protection systems were installed in these zone This item is considered close (Closed) Open Item (373/81-00-97B(DRP)): This open item tracked Unit 1 Operating License Condition 2.C(30)(k) and TMI Item II.K.3.15 which required tne licensee prior to startup after the first refueling outage to modify break detection logic to prevent spurious isolation of the Reactor Core Isolation Cooling (RCIC) system. The licensee added a'three second time delay to the isolation circuitry by replacing three interlock relays with time delay relays; this will prevent flow spikes from initiating a system isolation. This license condition is considered close (Closed) Violation (373/86018-01(DRP)): Technical staff operated the charging water supply valve to the scram accumulator with an equipment out of service tag still attached. The individual reviewed requirements of the out of service procedure and the importance of following the equipment out of service p'rogra (Closed) Violation (373/86018-04(DRP)): The licensee failed to adhere

to the fuel loadi'ig procedure and inserted a wrong fuel bundle into the reactor in response to this violation

(1) the Nuclear Component Transfer List was revised; (2) all fuel handling personnel have been trained on importance of proper communications and attention to detail; and (3) the fuel handling foreman involved in this event was counselled.

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(Closed) Violation (373/86018-03A,03B,03C(DRP)): A fuel bundle was inserted into quadrant A of the core while the quadrant A SRM detector was not inserted to its normal operating'

leve Comunications between refuel floor and the NSO in control room were not clear and_ concise, nor were verbal instructions repeated bac Personnel on the refuel platform did not notify the control room when moving over the reactor cor The "A" SRM was reinserted and all personnel associated with fuel handling activities were trained on the event and procedures revised to include proper. communication requirement (Closed) Violation (374/86003-01(DRP)): The HPCI minimum flow valve was taken out of service in the Open" position without considering all Technical Specifications applicable _to this valve. Procedure LAP-900-4, " Equipment Out of Service," has been revised, a memorandum was issued from the General Office, Nuclear Stations Division, and the event discussed with the shift crews and shift engineer (Closed). Violation (373/86025-01A(DRP)): An operator did not place switch 1B21H-S19D to the " Test" position while performing LES-PC-107,

"TIP System Logic Test." The operator placed switch IB21H-S79D in test which caused the shutdown cooling system to isolate. The operator involved in the event was counselled on the even (0 pen) SER (License Condition 2.C(25)(d))(373/81000130): During an NRC inspection.three types of problems regarding fire doors were identifie The three problems were:

(a) Certain doors had been installed with nonlabeled frames or certain doors were larger than those tested and were therefore, unlabele (b) Certain double doors had been installed with electric strike The electric strikes are only accepted by the testing laboratory for use in single doors, and (c) ~ Certain fire doors had been replaced with 21/2-inch thick steel'

doors which had not been tested, and were therefore, unlabele By letter dated June 15, 1983, the licensee described the program under-taken to resolve this license condition. Subsequently, by letter dated July 8, 1983, NRR stated that the review of the licensee's program meets NRC requirements. In addition, by letter dated April 24, 1986, the licensee again provided a similar description of the program undertaken to resolve this license condition. On May 28 and September 4, 1986, a Region III inspector verified that nine UL labeled, three hour fire rated

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door assemblies numbered 49, 58, 222, 251, 257, 262, 265, 268, and 302, have been installed and further, an additional twenty of the modified door frames were verified to reflect the configuration as described in Modification Package 1-1-84-069. This portion of the license condition is considered close Regarding an oversized bullet resistance door assembly numbered 299, the inspector verified by visual inspection that a UL labeled bullet resistant and Class A three hour fire door has been installed in an entrance /exitway to the control room. This portion of the license condition is also considered close On September 4,1986, the inspector observed that door locations 285, 394, and 893 have installed a UL labeled Class A three hour fire door at each location. This portion of the license condition is also considered close Regarding the fire door stop modifications of which six questionable door stops' exist, the licensee chose to have their Quality Control (QC) Depart-ment personnel obtain a sample of an approved fire door stop and compare that configuration to the six field installed door stops in question. A QC inspector found the six configurations to be acceptable. Subsequently, on September 4, 1986, the licensee provided a UL letter dated May 15, 1986, regarding fire door stops. The May 15, 1986 UL letter and the licensee's letters of June 15, 1983 and September 12, 1986, were sent to NRR for revie The licensee is pursuing resolution of this remaining open portion of the'

license condition with NR Due to radiation / contamination concerns, certain fire door assemblies discussed above could only be inspected on one side of the fire barrie During the inspector's two inspection visits, certain corrections and clarifications of the licensee's June 15, 1983 and April 24, 1986 letters were identified. At the exit meeting of September 4,1986, CECO's Nuclear Licensing Administrator (corporate) acknowledged that a resubmittal of-these letters with the necessary corrections would be forthcomin . Operational Safety Verification (71707)

The inspector observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the inspection period. The inspector verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of Units 1 and 2 reactor buildings and turbine buildings were conducted to observ'e plant equipment conditions, including potential fire hazards, fluid leaks and excessiv'e vibrations and to verify that maintenance requests had been -initiated for equipment in need of maintenance. The inspector by observation and direct interview verified that the physical security plan was being implemented in accordance with the station security pla .

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The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection control During the month of September 1986, the inspector walked down the accessible portions of the following systems to-verify operability:

Unit 1 and 2 A&B Diesel Generators Unit 1 and 2 Standby Gas Treatment Systems Unit 1 and 2 Division 1 and 2 Emergency Core Cooling Systems On September 8, 1986 the licensee informed the inspectors that Group 2 and 4 isolations occurred on Unit 1 and a Group 4 isolation occurred on Unit 2 and both trains of Standby Gas Treatment (SBGT) starte Investigation into the event identified that while performing a modification walkdown following replacement of SOR switch 1B21-N026BB, (-50" level) on Unit 1, the licensee identified the field leads on the terminal strip were on the opposite side as the wiring diagram showe Station construction requested an out of service (00S) to change the terminals. An 00S was run on September 5, 1986 which prevented the Group 1,~ 3, and 5 isolations on -50" level, but did not prevent the half isolation for Groups 2 and 4. The terminal leads were swapped and the instrument was valved back in partially clearing the 00S. The switch was now ready for testin On September 8, 1986 the Instrument Maintenance (IM) Department requested permission to_ perform a Technical Specification required surveillance, LIS-NB-102, " Unit 1 Reactor Vessel Low Low Water Level MSIV Isolation Calibration". The Shift Engineer knew tne N026BB switch was 00S and had the IM foreman check the 00S and found it in the temporary cleared box in the Unit 1 Nuclear Station Operator's (NS0's) box. The Shift-Engineer thought the entire 00S was temporarily cleared for testing; however, the electrical portion was not cleared and returned to servic The Shift Engineer, Shift Control Room Engineer (SCRE), and Nuclear Station Operator (NS0) then. authorized the surveillance to commence. .The

" Precautions" of the LIS stated, '.' Request permission from NS0 to perform

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test and have operator verify no Group I isolation tests are in progress,

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or alarm conditions exist. Notify NS0 upon completion of.this test."

Included also in the " Precautions" were the alarms associated with each switch tested. The NSO only ve~rified that the Group I isolation was not alarmed and did not recognize the " Division 2 Reactor Vessel Wtr LVL 2 Lo" alarm was also up which indicates ~a half isolation for Groups 2 and 4 on low low water leve After receiving authorization to do the surveillance, the IM proceeded in accordance with the procedure to place a test switch into the " Test" position which completed the logic for the Group 2 and 4 isolations on Unit i and Group 4 isolation on Unit 2. Since the station has a common secondary containment, a Group 4 isolation on reactor building ventilation

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on one unit also causes a reactor building ventilation isolation on the j other unit. All systems functioned as expected after receiving the

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isolation signal _. The shift acted quickly to restore reactor building ventilation and shut down the Standby Gas Treatment Systems. Unit I was l

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in Cold Shutdown and Unit 2 was at 85% power at the time. The licensee identified this event to the residents and the inspectors reviewed the corrective action to prevent similar recurrence. In accordance with 10 CFR, Part 2, Appendix.C, no Notice of Violation is being issued for this violatio The inspector toured portions of the reactor building, auxiliary building, and turbine building with the plant manager. The overall cleanliness of the station at that time was good. The plant manager noted areas that needed work and cleaning up. A later tour by the inspector determined that most of the problem areas were cleaned ~u . Monthly Surveillance Observation (61726)

The inspector observed Technical Specification. required surveillance testing and verified for actual activities observed that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation were met, that removal and restoration of the affected components were

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accomplished, that test results conformed with Technical Specification and procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne The inspector witnessed portions of the following test activity:

LES C0-02 Diesel Generator' Rooms C02 System Channel Functional Test LTS-1100-4 Scram Time Testing LIS-NB-101 Reactor Vessel Low Water Level Scram.and Primary Containment 1 solation Calibration On September 9, 1986 at 7:00 p.m. CDT, Unit 1 performed a reactor vessel water level drop test at atmospheric pressure to confirm the reactor vessel low water level scram setpoint. The water. level drop test was performed to verify the actual reactor vessel water level at which a reactor scram would occur. The switches being tested were SOR differential pressure switches which control the reactor vessel low level scram and the reactor vessel low level Automatic Depressurization System (ADS) permissive signals.

i The test showed that the switches actuated at reactor vessel water

, levels between +18.7 to +19.8 inches. For reference, the Technical l

Specifications setpoint is +12.5 inches. The switches have been reset to trip at approximately +19.4 inches to allow for setpoint drift when the plant is operating. All systems functioned as expected. Upon confirming switch actuation, the reactor vessel water level was brought back up to normal operating level.

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On September 17, 1986, during a planned reactor scram (refer to Paragraph 12), the reactor water level dropped low enough to actuate 3 of the 4 level 3 reactor water level SOR switches. Concerns over why the fourth S0R switch had not actuated prompted conversations between the licensee and the NRC and a commitment by the licensee to perform two (2) more level drop tests, one at atmospheric pressure and a second at rated reactor pressur On September 20, 1986, at 10:00 p.m., the licensee conducted the second SOR differential pressure switch reactor vessel water level drop test with reactor pressure at atmospheric. The SOR level 3 switches tripped from 17.9" to 19.2". All switches-functioned satisfactorily and the licensee commenced a reactor startu On September 24, 1986 at 3:00 p.m. with reactor pressure having remained at rated pressure for approximately 91 hours0.00105 days <br />0.0253 hours <br />1.50463e-4 weeks <br />3.46255e-5 months <br />, the licensee conducted a third SOR reactor vessel level drop test with the reactor pressure at approximately 950 psi. The SOR level 3 switches tripped from 14.8"~to 17.9". All switches functioned satisfactorily to the licensee's progra On September 15, 1986 the licensee notified the residents that a Unit 2 alarm on high suppression pool level ' required by Technical Specifica-tion 4.6.2.1.c was not operable. This condition was found originally on Unit 1 during the onsite review in preparation for the startup of the unit after an 11 month refueling outage. The licensee determined that all other alarms required by Technical Specifications were operabl A high level alarm was operable on the Special Parameter Display System (SPDS) and would have indicated high suppression pool level at the Technical Specification 3.6.2.1 Limiting Condition for Operation (LC0)

value of 26 feet 10 inches, two inches higher than the alarm setpoint in Technical Specification 4.6.2.~1.c. Also, the high suppression pool level alarm for High Pressure Core Spray (HPCS) was found operable at 26 feet 9 inches, one inch higher than Technical Specification 4.6.2. This alarm had not been calibrated since August 1985 for Unit 2 when the piping from the Condensate Storage (CY) tank to the HPCS pump was found damaged, and the piping had been isolated. However, a calibration check of this alarm identified its operability on both units. The licensee had also performed a daily surveillance check of the suppression pool level to assure it was within specifications. Thus, the licensee had sufficient indication to identify when the suppression pool level was outside the LC0 condition without the suppression pool high level 'larm of Technical Specification 4.6.2. The licensee has subsequently established an alarm on the computer for high suppression pool level at the Technical Specification 4.6.2. limits. Since the licensee identified this condition to the residents and have taken action to prevent its recurrence, and the failure of alarm function had no safety significance, no notice of violation will be issued

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in accordance 10 CFR, Part 2, Appendix C, Enforcement Polic . _ -

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Monthly Maintenance'0bservation (62703)

On ' September 9,1986 at 8:10 a.m. CDT. -in preparation for replacing a non Environmentally Qualified thermocoupleLwith one that was Environmentally 3-Qualified, the instrument maintenance mechanics detenninated thermocouple 2E12-N005B, the 2B RHR heat exchanger service water outlet temperature thermocouple.- At approximately 4:00 p.m. CDT'on September. 17, 1986, the NSO was reviewing surveillance LOS-RX-M1,'" Remote Shutdown Monitoring Instrumentation Channel Check" and determined that the 2B RHR Hx. service

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water effluent temperature meter on the remote shutdown panel was

. inoperable. The cause was determined to be the determinated leads on thermocouple 2E12-N005B. A new thermocouple was installed and returned to service on September 18,1986 at 2:25 a.m., 9 days after the thermocouple

was determinate ~

Technical Specification 3.3.7.4 requires remote shutdown instrumentation

.to be operable with readouts displayed in the remote shutdown panel ;

external to the control room. The required instrumentation included the '

Residual Heat Removal (RHR) service water temperature. With any of the required monitoring instru-mentation inoperable, the instrumentation shall be restored to operable status.within seven days or the plant shall be in at-least hot shutdown within the next twelve hours. Contrary to the above, the 2B RHR heat exchanger service water outlet temperature instrument was inoperable. from 8

10 a.m. CDT on' September 9,1986 until-2:25 am September 18, 1986, a total-of nine days, and the unit was not

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placed in hot shutdown after 7 days. This is considered a violation (374/86036-01(DRP)).

i As the thermocouple is a dual element sensor, the~ lifted leads also caused the discharge cooling water temperature indi_cator to read high, initiating the alarm'in the control room for Residual Heat Removal (RHR)

Heat Exchanger (Hx) Discharge Cooling Water Hx A/B Temperature. A review

of the control room annunciator and annunciator procedure, 2H13-601C301, i for " Residual Heat Removal (RHR) Heat Exchanger-(Hx) D.ischarge Cooling Water Hx A/B Temperature Hi," identified no references to Technical

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Specification 3/4.3.7.4, " Remote. Shutdown Monitoring Instrumentation."

, 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings

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requires that activities affecting quality shal_1 be prescribed by.. . .

procedures . . . appropriate to the circumstances . . . Contrary to the above, the control room annunciator alarm procedure LOA 2H13-P601 C301,

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" Residual Heat Removal Heat Exchanger Discharge Cooling Water Heat Exchanger A/B Temperature Hi" was found not to be appropriate in that it did not include a reference to Technical Specification 3.3.7.4 Limiting

Condition for Operation for remote shutdown monitoring instrumentation of i .which the RHR Hx service water discharge temperature indication is a part '

of. This is considered a violation (374/86036-02(DRP)).

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Technical Specification 6.2.A.1 states, " Detailed written procedures shall be prepared, approved and adhered to for applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978." Regulatory Guide 1.33, Appendix-A, includes procedures for control of equipment. LaSalle's administrative procedures for control of equipment includes Procedure LAP 1300-1, "k'ork Request" which states,

"The Shift Engineer shall review Technical Specification requirements and

verify that equipment can be removed from service and is not required to be operable." Contrary to the above, on September 9, 1986 the Shift Engineer failed to review the Technical Specification requirements section of the work requirements which had been marked "yes" before authorizing the removal of the equipment from ;ervice. This is considered a violation (374/86036-05(DRP)). Training (41400)

The inspector, through discussions with personnel and a review of training records, evaluated the licensee's training program for operations of maintenance personnel and determined that the general knowledge of the individuals was sufficient for their assigned task . Licensee Event Reports (92700)

Through direct observations, discussions with licensee personnel, and review of records, the following Licensee Event Reports (LER's) were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical Specification (Closed) 374/86012-00 - With Unit 2 in Cold Shutdown, electrical terminations at the inboard and outboard Main Steam Isolation Valve

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. limit switches and outboard feedwater check valve limit switches and solenoids were determined not to be installed in an Environmentally Qualified configuration. Followup on this event was documented in Inspection Report 374/86035. Additional inspections will be tracked by item (374/86035-01(DRS)).

(Closed) 374/86015-00 - deactor Water Cleanup (RWCU) system isolation on high differential flow due to flow losses through the "B" Hx shell side relief valve. The valve was removed, inspected, repaired and adjusted for proper setpoin (Closed) 374/86013-00 - With Unit 2 in Cold Shutdown, electrical terminations at ASCO solenoid valves were determined not to be in' stalled in an Environmentally Qualified configuration. Followup on this items was documented in Inspection Report 374/86035. Additional inspections will be tracked by item (374/86035-01(DRS)).

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(Closec') 373/86034-00 - With Unit 1 in Cold Shutdown, the Division III normal 4.16KV feedbreaker to Engineered Safety Feature (ESF). Bus 143 tripped open resulting in bus undervoltage and subsequent auto-start-of the IB diesel generator. The cause was spurious actuation of a System Auxiliary Transformer (SAT) relay. The relay was replace (Closed) 373/86035-00 - IB Diesel Generator failed to start during a post-maintenance test. The cause was an Agastat time delay relay timing out in less than one second instead of its normal setpoint of forty-fiv seconds. Time delay relay was replaced and diesel was retested satisfactorily per LOS-DG-M ~

(Closed) 373/86022-01 Shutdown Cooling (SDC) Isolation during surveillance. Residual Heat Removal (RHR) SDC suction inboard isolation valve inadvertently closed, tripping the "B" RHR pump. The revision to this LER states that event was discussed with all shift personnel. A Notice of Violation was issued in Inspection Report (374/86035-01(DRS)).

(Closed) 373/86033-00 - With Unit 1 in Cold Shutdown, Reactor Core Isolation Cooling (RCIC) High Ambient Temperature Leak Detection module tripped twice within two hours which caused inboard Division II isolation signals. This was an' Engineered Safety Feature (ESF) actuatio Random failure of electronic component (s) within the module was suspected as cause. The module was replace (Closed) 374/86014-00 - With Unit 2 in Cold Shutdown, electrical terminations at equipment utilizing kapton insulated conductors were determined not to be installed in an Environmentally Qualified configuration'. Followup on this item was documented in Inspection Report No. 374/86035. Additional inspections will be tracked by item (374/86035-01(DRS)). Temporary Instruction TI 2515/82 (25582)

This closes the action requested by memorandum on both units from C. E. Norelius dated August 25, 1986 which forwarded TI 2515/82. The resident inspectors reviewed the licensee's actions regarding IE Bulletin 86-01 regarding minimum flow logic problems that could disable Residual Heat Removal (RHR) pumps. This IE Bulletin was previously reviewed and documented in Inspection Report No. 373/86025;374/86026(DRP).

The problem does not exist at LaSalle since each RHR loop has a separate minimum flow valve and flow 1 cop instrumentatio . TMI Action Plan Requirement Followup (25565)

Closed (0 pen Item 373/81000-93): TMI Action Item II.E.4.2. Containment vent and purge valve modification. New valve, valve actuators and supports (hangers, snubbers) have been installed and tested satisfactoril Closed (0 pen Item 373/81000-97C): TMI Action Item II.K.3.18. License Condition 2.C.30.L.b. The licensee modified the ADS logic to bypass the high drywell ' pressure trip with a run out timer started on low pressure ECCS initiation level.

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10. -Regional ~ Requests (92705)-

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In, response to a memorandum from W~ Guldemond.to G. Wright dated

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August 29, 1986, which forwarded a memorandum from J. Partelow to C. Norelius dated February 19, 1986, information concerning LaSalle's

. seismic monitoring instrumentation was provided to Region-III. The-

-requested information consisted of a description'of the instrumentation, the. applicable Technical Specifications, non-Technical Specification surveillances performed, preventive' maintenance performed, and failure date for the last twenty-four month . Part 21 Followup-(92716)

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.The inspectors received a 10CFR, Part 21 notification.concerning SOR In pressure switches. The Part 21 was sent by memorandum from W. G. Guldemond to G. C. Wright dated August 27, 1986.. The residents forwarded'a copy of the Part 21 to the technical staff supervisor. The technical staff super-visor then showed the inspector where this Part 21 had been addressed by ,

the Onsite Review Committee during the Unit 1 startup. The switches had been_ replaced where the licensee determined they needed to be. replace Unit 2 safety related 50R pressure switches are presently being tested every two weeks to assure operability and will be replaced during the upcoming refueling outage in January 1987. This Part 21 is considered closed (373/86035-01;374/86036-04(DRP)).

12. Unit Trips (93702)

On September 21, 1986, Unit I was in the process of being started up from Cold Shutdown in accordance with station procedure LGP-1-1. Step F. directed that the mode switch be placed in the STARTUP position. At.5:17 a.m. hours, the NS0 attempted to move the mode switch to STARTUP from the SHUTDOWN position. The switch was turned too far and reached the RUN position. At this time, a Group-I (MSIV) isolation and a reactor scram occurred. No rod movement occurred since all rods were fully inserte ~

All automatic actuations occurred as designed. The mode-switch was returned first to the STARTUP position, then to SHUTDOWN while the event was reviewed. Startup recommenced at 6:32 a.m..

! - The apparent cause seemed to be inattention by the NSO.

The mode switch was operated without consideration of stopping the switch

. in the proper position. Although this switch is difficult to turn, other operators have been successful in properly operating it. The safety l ,

significance of the event was minor as the unit was already in Cold

, Shutdown.

In consideration of 10 CFR, Part 2, Appendix C, a Notice of Violation will not be issued for the above failure to follow procedure.

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A planned scram from 9% power was conducted on Unit 1 at 8:10'p.m. CDT on September 117, 1986 to test the Scram Discharge Volume Vent and Drain Modification. Reactor water level dropped to 12.1". Level 3 switches _A, C, and D tripped at 13.5", 14.1", and 13.0",.respectively. While the B switch did not trip, corrective action has been.taken as described in-Paragraph . Refueling /0utage (71711)

On September _ 17, 1986 Unit 1 commenced restart following an extended refuel and modification outage that started in October.1985. The reactor-

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was critical as of 6:34 a.m. CDT. Major activities completed during the outage included the~ installation of Environmentally Qualified electrical equipment,-testing of mechanical snubbers, inservice inspection and Induction Heat Stress Improvement (IHSI) of primary system piping welds and approximately 134 modifications. The unit also had been on an NRC hold since June 1986 pending resolution of setpoint drift problems with SOR, Inc. differential pressure switches. NRR and Region III released this hold on September 16, 1986 following a review of the licensee's short term action plan which included setpoint adjustment and increased calibration frequenc In preparation for the startup,- the licensee _ tested-as much safety and non-safety rotated equipment as possible. The special program was to assure that all systems were operational or that equipment failures were identified and corrected to avoid delays in the_startup. The program was

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very successful in that required testing of equipment during the startup, (due to mode conditions) proved that the equipment was operational with

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very few failures. After the scheduled SCRAM the unit's return to service, due to minimize equipment problems, was smooth and prompt.

i 14. Exit Interview (30703)

The inspectors met with licensee representatives (denoted in Paragraph 1)

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summarized the scope and findings of the inspection activities. The I licensee acknowledged these findings. The inspector also discussed the l

likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.

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The licensee did not identify any such documents or processes as proprietary.

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