IR 05000338/1988022

Insp Repts 50-338/88-22 & 50-339/88-22 on 880716-0819. Violations Noted.Major Areas Inspected:Plant Status,Maint, Sueveillance,Esf Walkdown,Operational Safety Verification, Operating Reactor Events & LER Followup

ML20155A191
Person / Time
Site:	North Anna
Issue date:	09/15/1988
From:	Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20155A185	List: ML20155A182 ML20155A186 ML20155A191
References
50-338-88-22, 50-339-88-22, NUDOCS 8810050242
Download: ML20155A191 (13)

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J* ' '4 UNITED STATES j o

]* NUCLEAR REGULATORY COMMISSION REGION 11

%e'.,.[ 101 MARIETTA ST., ATLANTA. GEORGIA 30323 Report Nos.: 50-338/88-22 and 50-339/88-22  ;

Licensee: Virginia Electric and Pcwer Company Richmond, VA 23261 Docket Nos.: 50-338 and 50-339 License No:.: NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted: fuly 16 - August 19, 1988 Inspectors: - /fh[

J. E. Caldwell, Seni6/ es ent Inspector Da'te Signed kh L. Ff.~ King, Resident Inpf4 tor 9h Y Date S'igned Appioved by: ~ F. S.'Cantrell, Section C) W 9//.f/7Y

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Dafe Signed Division of Reactor Projects SUMMARY Scope: This routine inspect.f on by the resident inspectors involved the following areas: plant status, maintenance, surveillance, ESF walkdown, operational safety verification, operating reactor events, licensee event report (LER) followup, and licensee action on previous

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enforcement matters. During the performance of this inspection, the i resident inspectors conducted reviews of the licensee's backshif t operations on the following days - July 18, 25, 26, and August 1, 2, 4, 5, 7, 10, 11, and 1 Results: Within the areas inspected, one violation was identified with three examples for failure to follow procedure, and one Inspector Followup Item (IFI).

(0 pen) IFI 338/88-22-01, followup on the cause of Unit 1 "C" main feedwater isolation va've failure to close (paragraph 3).

(0 pen) Violation 338/88-22-02, failure to follow a containment entry ,

procedure with three examples (paragraph 6).

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8810050242 880913 PDR ADOCK 05000338 0 PDC

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REPORT DETAILS Persons Contacted Licensee Employees M. Cowling, Assistant Station Manager J. Downs, Superintendent, Administrative Services

• R. Orfsco11, Quality Control Manager R. Enfinger, Assistant Station Manager G. Gordon, Electrical Supervisor L. Hartz, Instrument Supervisor D. Heacock, Superintendent, Technical Services

• G. Kane, Station Manager M. Kansler, Superintendent, Maintenance '

• T. Maddy, Supervisor, Security T. Porter, Superintendent, Engineering J. Stall, Superintendent, Operations A. Stafford, Superintendent, Health Physics F. Terminella, Quality Assurance Supervisor D. Thomas, Mechanical Maintenance Supervisor

• 0. VandeWalle, Corporate Licensing Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personne * Attended exit interview NRC Management Site Visit: M. Ernst, Deputy Regional Administrator; C. Hehl, Deputy Director, Division of Reactor Projects (DRP); B. Wilson, Chief, Reactor Projects Branch 2, DRP; H. Berkow, Director, Projects Directorate II-2, Nuclear Reactor Regulation (NRR); L. Engle, Project Manager, NRR; and C. Pate11, Project Manager, NRR visited the North Anna site on July 27, 1938. The visit involved a tour of the station and the presentation of the SALP results to the license . Plant Status Unit 1 Unit 1 began the inspection period operating at approximately 100% powe On August 6, Unit 1 tripped from 100*. power due to a steam flow / feed flow mismatch with a low water level in the "B" steam generator (S/G) (see section 7 for details). Prior to the trip, the unit had been operating at approximately 100% power since March 25, 198 On August 8, the unit restarted and, following the secondary chemistry holds and instrumentation repairs, achieved 100% power on August 1 Unit 1 operated at approximately 100% power for the remainder of the inspection perio .

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REPORT DETAILS Persons Contacted Licensee Employees M. Bowling, Assistant Station Manager J. Downs, Superintendent, Administrative Services

" Driscoll, Quality Control Manager R. Enfinger, Assistant Station Manager G. Gordon, Electrical Supervisor L. Hartz, Instrument Supervisor D. Heacock, Superintendent, Technical Services

• Kane, Station Manager M. Kansler, Superintendent, Maintenance

• T. Maddy, Supervisor, Security T. Porter, Superintendent, Engineering J. Stall, Superintendent, Operations A. Stafford, Superintendent, health Physics F. Terminella, Quality Assurance Supervisor D. Thomas, Mechanical Maintenance Supervisor

• D. VandeWalle, Corporate Licensing Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personne * Attended exit interview NRC Management Site Visit: M. Ernst, Deputy Regional Administrator; C. Hehl, Deputy Director, Division of Reactor Projects (DRP); B. Wilson, Chief, Reactor Projects Branch 2, DRP; H. Berkow, Director, Projects Directorate 11-2, Nuclear Reactor Regulation (NRR); L. Engle, Project Manager, NRR; and C. Patell, Project Manager, NRR visited the North Anna site on July 27, 1938. The visit involved a tour of the station and the .

presentation of the SALP results to the license . Plant Status Unit 1 Unit 1 began the inspection period operating at approvimately 100% powe On August 6, Unit 1 tripped from 100% power due to a steam flow / feed flow mismatch with a low water level in the "B" steam generator (S/G) (see section 7 for details). Prior to the trip, the unit had been operating at approximately 100% power since March 25, 198 On August 8, the unit restarted and, following the secondary chemistry holds and instrumentation repairs, achieved 100% power on August 1 Unit 1 operated at approximately 100% power for the remainder of the inspection perio . .

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Unit 2 Unit 2 began and ended the inspection period operating at approximately 100*4 powe Both Units On July 18, the licensee requested and received discretionary enforcement from the NRC to allow them to exceed the Technical Specification (TS)

containment temperature limit of 105 degrees Fahrenheit. At the time of the request, both containments were approximately 103 degrees Fahrenheit due to the inoperability of the mechanical chiller during an extended period of 95-100 degree waathe The licensee had submitted a TS amendment to the NRC in March 1988 to' change the TS containment tempera-ture limit to 120 degrees Fahrenhei Based on this submittal, the NRC granted the licensee discretionary enforcement to allow the containment temperature to exceed 105 degrees Fahrenheit, but not to exceed 110 degrees Fahrenheit for the time necessary to repair the mechanical chiller. On July 19, the mechanical chiller was repaired. Technically, the discretionary enforcement was not required since only Unit 2 exceeded the 105 degree F limits and was returned to less than the limit well within the TS action statement time limit. Both units' containments are being maintained around 100 degree On July 27, 1988, Region II and headquarters personnel presented the SALP results to the North Anna Station management and staff. The presentation was conducted at the site in the North Anna Information Center (NAIC)

auditorium. The Virginia Electric and Power Company personnel who attended the presentation included J. Ferguson, President and C.E.O. ; Stewart, Senior Vice President, Power Operations; D. Cruden, Vice President, Nuclear Operations; G. Kane, Station Manager, North Anna; R. Saunders, Manager, Nuclear Programs; J. Wilson, Manager, Nuclear Operations Support; N. Hardwick, Manager, Nuclear Licensing; R. Hardwick, 1 Manager, Quality Assurance; R. Enfinger, Assistant Station Manager, North Anna; M. Bowling, Assistant Station Manager, North Anne., and approximately 150 other station and corporate personne NRC representatives are identified in paragraph . Maintenance (62703)

Station maintenance activities affecting safety related systems and components were cbserved/ reviewed to ascertain that the activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with the Technical Specifications (TS).

On August 4, the inspectors witnessed the licensee adjust the inboard packing on motor driven auxiliary feedwater pump 2-FW-P-3A. The packing adjustment was performed per Mechanical Maintenance Procedure MMP-C-GP-1, Inspection and Repair of Safety Related Pumps in General. The only noted

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problem was identified by the operator and mechanics performing the wor The outboard packing was also leaking excessively and needed adjustmen Since the work order only addressed the inboard packing adjustment, the mechanics were unable to adjust the outboard packino without violating procedures. The pump was secured, and a work request was initiated to adjust the outboard packing during the next scheduled pump operation. The leak was not of a nature to affect the operability o'/ the pump. No other problems were note On August 7, the inspectors witnessed portions of the MOVATS test of the

"C" main feedwater line motor operated isolation valve. The maintenance, performed per Electrical Maintenance Procedure EMP-P-MOV-3, Predictive Analysis of MOVs, was necessary because the valve failed to fully close during the reactor trip that occurred the day before (see discussions of this event in the end of section 7). The electrician informed the inspectors that the valve's limit switches for both opening and closing were of f and needed adjustment. The closing limit switch appears to be the cause of the valve failing to fully close when the automatic closure signal was received. No problems were identified with the performance of the maintenanc The inspector has requested the licensee provide information concerning the cause of limit switches being out of adjustment. This will be identified as Inspector Follow-up Item (IFI 338/88-22-01).

On August 11, the inspectors witnessed the calibration of feedwater flow instrument 1-FW-FI-1486 for the "B" main feedwater line per Instrument and Control Proedure ICP-FW-1-F-1486, SG 1B Feed Flow Protection Channel I The calibration was being performed because the feed flow indication in the control room was out of the TS required tolerance. Unit 1 was in the process of a startup at the time, and the licensee had placed the protection channel associated with the feed flow instrument in trip. The inspector observed that the technicians were unable to calibrate the instrument. Folicwing the determination that the calibratien procedure could not be completed successfully, the licensee attempted to repair the transmitte This repair was also unsuccessful, consequently, the licensee replaced the feed flow transmitter, calibrated the new instrument, and placed the instrumentation back on linc. No problems were identified by the inspector, ho violations or deviations were identif'.e . Surveillance (61726)

The inspectors observed / reviewed TS required testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation (LCO) were met, and that any deficiencies identified were properly reviewed and resolve .

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The licensee informed the inspectors that on July 23, during the perfor-mance of 1-PT-31.7.2, Pressurizer Level Channel II (L-460) Functional Test, an Eutomatic isolation of the charging system letdown line occurre The licensee investigated the event and determineo the cause of the isolation was an inadequate procedur The procedure required the operator to olace a defeat switch in the wrong position, and consequently, the automatic isolation of letdown occurred when the test signal was generate Further investigation by the licensee determined that 1-PT-31.7.2 had recently been revised, and this was the first time the procedure had been used since the revision. A review showed that the switch position was correct in the previous procedure, consequently, the revision and suosequent int.dequate review resulted in an inadequate procedur Following the letdown isolation, the operators were able to re-establish letdown withot;t causing a transient on the unit. A review by the inspector did not identify any safety concerns reltting to the even However, TS 6.8.1.c requires that w itten procedures to be established, imple-mented, and maintained covering surveillance and test activities of safety related equipment. The failure of the licensee to establish and maintain an adequate procedure to perform a surveillance on the pressurizer level channel without resulting in automatic action is a violation of TS 6.8.1.c. Since this violation was identified, investigated, and corrected by the licensee and meets the criteria of 10 CFR 2, Appendix C, for licensee identification, this item will be considered a Licensee Identified Violation (LIV 338/88-22-03, Failure to Prov'de Adequate Test Procedure). LIVs are considered first-time occurrence violations which meet the NRC enforcement policy criteria for exemption from issuance of a Notice of Violation. These items are identified to allow for proper evaluation of corrective actions in the event that similar events occur in the future.

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On July 25, the inspectors witnessed the surveillance test on the Unit 2

"B" component cooling water pump. The test was conducted per test procedure 2-PT-74.28, Component Cooling Pump (2-CC-P-18). The inspectors did not identify any problems associated with the performance of the tes The licensee informed the inspectors that there was an inadvertent l automatic start of the 2-CH-P-1A charging pump on July 26. This pump,

! which is also the high head safety injection (HHSI) pump, was autometi-cally started due to a safety injection related undervoltage signal. The inadvertant start was caused by personnel error during tne performance of surveillance test procedure 2-PT-36.9.1.J. Degraded Voltage / Loss of Voltage Functional Test, 2J Bus. The personnel error involved the improper reinstallation of the relay cover on relay 27C such that the contacts remained closed even af ter tht: relay was de-energize This relay, 27C, which becomes energized on an undervoltage signal, or in this case, a test signal, will start the Unit 2 "A" and "C" charning pumps. Prior to the initiation of the test signal, the licensee p aced

! the "A" charging punp in pull to lock, by procedure, to prevent the punp

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from automatically starting. The "C" charging pump was already operatin Following the initiation of the test signal, test personnel verified that the relay 27C was energized, replaced the relay cover, and removed the test signal which de-enerigized relay 27 The licensee took the "Ad charging pump controller out of the pull to lock position. As soon as the controller was taken out of pull to lock, the Unit 2 "A" charging pump automatically starte The operator verified that this pump was not required to be operating, and secured the pump by placing the controller back in pull to loc The licensee investigated the event and found that the cover on relay 27C had been misaligned when it was reinstalled. Following the removal of the cover and proper reinstallation, the automatic start signal no longer existed. Using a similar relay, the licensee demonstrated to the inspectors the sequence of events which could lead to this situation. The licensee was able to install the relay cover in such a way to cause the relay contacts to remain closed even though the relay was not energize The licensee determined the event to be reportable. A four-hour report was made and an LER was issue The inspectors will followup on the corrective actions, and close out the issue during the review and close out of LER 88-02, Inadvertent Engineering Safety Features System Actuatio On August 2,1988, the inspe-tors witnessed test 2-PT-71.1, Steam Driven Auxiliary Feedwater Pump and Valve Tes The test was performed satisfactoril On August 17, the inspectors witnessed portions of the surveillance test on one of the hydrogen recombiners per 1-PT-68.1.2, Hydrogen Recombiner Functional Test 2-HC-HC-1. During the performance of the test, several problems were identified associated with non technical issue The first problem involved steps 4.9.1. 4.9.2, 4.13, 4.14, 4.20, 4.21, 4.33, and 4.34 which identified the motor control switches for the blower and the cooling fan differently than the actual label plates. The second problem involved the placement of the master control switch (HS-1) in the start position, but the procedure did not take the switch out of star The licensee corrected both of these discreoancies with a procedure deviatio The inspectors did not identify any other problem On August 18, the inspectors witnessed 2 .0T-57.1A, which was the 2-SI-P-1A low head safety injection pump tes The test was performed satisfactoril No violations or deviations were identifie . ESF System Walkdown (71710)

The following selected ESF systems were verified operable by performing a walkdown of the accessible and essential portions of the systems on August 11, 198 Using procedure 1-0P-21.9A, Va've Checkoff Control Room

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Bottled Air Pressurization System, the resident inspector walked down the control room bottled air syste The following comments were noted: Fill connection sample valves 1-CA-33 and 2-CA-36 and, the pigtail isolation valves 2-CA-31-1 thru 2-CA-31-42 were observed not to be labele Bottles 1-CA-1-7, 1-CA-1-9, and 1-CA-1-10 are labeled out of sequenc No violations or deviations were identifie . Operational Safety Verification (71707)

By observations during the inspection period, the inspectors verified that the control room manning requirements were being met. In addition, the inspectors observed shif t turnover to verify that continuity of system status was maintained. The inspectors periodically questioned shift personnel relative to their awareness of plant condition Through log review and plant tours, the inspectors verified compliance with selected TS and LCO In the course of the monthly activities, the resident inspectors included a review of the licensee's physical security program. The performance of i various shifts of the security force were observed in the conduct of daily activities to include: protected and vital areas access controls; searching of personnel, packages and vehicles; badge issuance and retrieval; escorting of visitors; patrols; and compensatory post On a regular basis, radiation work permits (RWP) were reviewed and the specific work activity was monitored to assure the activities were being conducted per the RWPs. Selected radiation protection instruments were periodically checked and equipment operability and calibration frequency was verifie The inspectors kept inform e >n a daily basis, of the overall status of both units and of any sd '

icant safety matter related to plant operations. Discussions held with plant management and various members of the operatite- teaff on a regular basis. Selected portions of operating logs and data s w ; were reviewed dail The inspectors conducted various plant tours and made frequent visits to the control room. Observations included: witnessing work activities in progress; verifying the status of operating and standby safety systems and equipment; confirming valve positions, instrument and recorder readings, and annuciator alarms; and observing housekeeping.

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On August 8, the inspector witnessed Unit 1 startup to criticalit No problems were encountered and the reactor was critical within the estimated critical positio On August il, the inspectors witnessed the licensee increasing power above the 5% chemistry hold point and cnanging from Mode 2 into Mode 1. When the licensee reached approximately 12%

power, just prior to placing the generator on line, Channel IV of the "B" feed flow instrumentation was determined to be inoperabl The licensee placed the protection channel in trip and decided to correct tne instrument problem prior to placing the turbine generator on line (see the end of paragraph 3). During the repair of the feed flow instrument, the inspector observed that Channel III of the "C" steam flow instrumentation had failed lo Subsequently, the licensee placed the steam flow protection channel in tri Also, during the time while the instrumentation was being repaired, the inspector observed the licensee vent pressure from the Primary Relief Tank (RPT) using Operating Procedure 1-0P- On August 12, following the repair of the feedwater flow instrument, the licensee, af ter verifying that the prob'eem with the steam flow instrument was not in the instrumentation, decided to continue with the startup with the steam flow protection channel in trip. With the unit at approximately 20 percent power, Channel III of "C" steam flow instrumentation came back into specification and was taken out of trip. The startup continued without further instrumentation problems. The licensee has written 1 work request for the "C" steam flow instrumentation to determine the cause of the proble This work request will be performed during the next available outag On August 9, 1988, at 1618, a first aid emergency was declared at Unit 1 containment hatch. Unit 1 was in Mode 2 at less than 5 percent power. A contractor employee experienced heat exhaustio He was administered oxygen and carried to the Health Physics office, where a nurse examined and released him to return to duty. The entry was made at 1528 by two health physics technicians and two contractor personnel to inject Furmanite into a leaky packing gland on a disc pressurization valve (RC-187) for the "A" cold leg isolation valv The inspector requested and received the maintenance history on 1-RC-18 The maintenance history indicates that 1-RC-187 had never had the packi replaced and the valve had not been scheduled to be repacked. Futher review of the event by the inspectors revealed that two previous entries had been made to determine the problems identified with the valv One entry identified the leak path and the other entry was an attempt to adjust the packing to stop the leak. Af ter adjusting the packing as much as possible, the valve still leaked and a decision was made to inject Furmanite into the valve. A review of the containment entry procedures by the resident inspector indicated the following:

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8 Attachment 1 of Administrative Procedure (AP) 20.9, Containment Ingress and Egres', is a subatmospheric containment entry checklis The resident obtained a copy of the checklist while the containment was being exited (on August 9). Only the portion of the checklist up to incore detectors tagged out was initialed. The inspector was told that several other steps had been completed but not signed off. Step 7.1 of the procedure requires that each department comolete the applicable sections of attachment 1 as the steps are completed. The failure of the licensee to follow AP 20.9 and complete the checklist as required will identified as a violation (338/88-22-02). In the entries made on August 8 at 0924 and 1618, the required wet bulb temperatures were not documented and the calculated stay times were not determined as required by step 7.14 of Administrative Procedure 2 The failure of the licensee to follow AP 20.9 will be identified as an additional example of violation (338/88-22-02).

7. Operating Reactor Events (93702)

The inspectors reviewed activities associated with the below listed reactor event The review included determination of cause, safety i significance, perfcemance of personnel and systems, and corrective actio The inspectors examined instrument recordings, computer printouts, operations journal entries, scram reports, and had discussions with operations, maintenance and engineering support personnel as appre?riat At 2257 on August 6, 1938, Unit 1 of the North Anna Power Station tripped due to a steam flow / feed flow mismatch with a coincident low steam generator (S/G) water level in the "B" S/G. Just prior to the reactor trip, the operators had placed the shunt reactors (additional inductive loads) in service at the request of the load dispatcher. These shunt reactors are loads directly of f of the 34.5 kv buses which supply the emergency buses through the reserve station service transformers (RSST).

Following the connection of the shunt reactors, the 34.5 kv buses decreased in voltage, and consequently, so did the 4160 volt emergency buses which are the secondary side of the RSSTs (34.5 kv/4.16 kv transforners). The design of the RSSTs include an automatic tap changer on the secondary (emergency bus) side of the transformer which will compensate for decreases in the primary side voltage by changing the taps necessary to maintain required voltage on the secondary side. However, in this case, the licensee determined that the automatic tap changer for the RSST supplying the Unit 1 J emergency bus did not operate. The 1 J bus sensed a degraded voltage and separated itself from the RSST. The 1 J emergency diesel generator (EOG) started and loaded onto the bus as designe The problem with the transfer of the 1 J emergency bus to the 1 J EDG in itself did not result in the reactor trip. However, some of the non-vital loads on the 1 J bus, which are shed during a degraded voltage situation, involve some secondary system steam valves which closed along with the

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feedwater recirculation valves which resulted in a steam /feedwater transien This transient resulted in a demand on the feedwater regulating valves to close. The "B" feedwater regulating valve failed to reopen resulting in the team flow / feed flow mismatch and low S/G water level trip signal. An inspection by the licensee revealed that the "B" feedwater regulating valve stem had broken, separating the disc from the actuator. Consequently, once the valve went closed the actuator could no longer reopen the valve. The licensee has experienced problems with feed regulating valve stems breaking in the past, and modifications have been I performed on both Unit 1 and Unit 2 feedwater regulating valve The modifications on the Unit 2 valves are more advanced, including a bigger stem, and appear to have solved the problem. The licensee had scheduled the same modifications on the Unit 1 valves during the next refueling outag Following the trip the Unit 1 feedwater regulating valves were inspected and repaired as necessar The "B" feedwater regulating valve stem and actuator were replace All of the systems operated as required with a few exceptions. The major problem following t'ie trip was the f ailure of the "C" main feedwater isolation valve to fully clos The failure of the feedwater system to fully isolate resulted in a cooldown below the normal 547 degrees F to approximately 538 degrees F with a resulting pressure decrease to 1870 psig. The licensee manually isolated feedwater and maintained S/G levels with the auxiliary feedwater system which was already in operation. The problem relating to the failure of the "C" feedwater isolation valve to close is discussed in Section 3 of this report. Followup will be via inspector follow-up item (IFI) 338/88-22-0 The only other problems associated with the trip were several valve position indicators whici, did not function properly; a problem with one of the steam dump valves, and the failure of the General Electric Transient Analysis recording systems to actuate. The inspectors will followup on the licensee's actions and closeout these issues based on the LER review and closecu No violations or deviations were identifie . Licensee Event Report (LER) Follow-up (90712)

The following LERs were reviewed and closed. The inspector verified that reporting requirements had been met, that causes had been identified, that corrective actions appeared appropriate, that generic applicability had been considered, and that the LER forms were complete. Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations of regulations or technical specifications (TS) conditions had been identifie .

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LERs that identify violation (s) of regulation (s) and that meet the criteria of 10 CFR, Part 2, Appendix C,Section V are identified as License.2 Identified Violations (LIV) in the following closecut paragraph LIVs are considered first-time occurrence violations which meet the NRC enforcement policy criteria for exemption from issuance of a Notice of Violation. These items are identified to allow for proper evaluation of corrective actions in the event that similar events occur in the future, (Closed) LER 338/87-12, Rev. 0: Inadvertent Partial Solid State Protection System Actuation A safety injection slave elay (K602) was energi:ed during the performance of Reactor Protection and Engineered Safety Features Response Time Test (Periodic Test 36.5). The root cause of the inadvertent actuation was procedure inadequacy. The procedures have been revised and approved by SNSO (Closed) LER 338/87-14, Rev. 0: Loss of RCS Inventory While In Cold Shutdown The licensee has issued an operations directive and station manager's memo notifying personnel to be aware of any testing not covered in the Final Safety Analysis Report (FSAR). It outlines the steps to be taken for a 10 CFR 50.59 evaluatio Training has also been accomplished for the operators on loss of inventor Other corrective actions are being tracked by the violations identified in inspection report 87-2 (Closed) LER 338/87-21, Rev. O and Rev. 1: Loss of Environmental Qualification of SI Accumulator Tank Pressure Transmitters STO-GN-0001, Instructions For DCP Preparation, has been revised to provide additional guidance and instructions for design change package (DCPs) which require the installation of equipment per the manufacturer's installation instructions, (Closed) LER 338,339/87-23, Rev. O and 1: Kaman Process Vent Normal Range Radiation Monitor Exceeded T.S. Action Statemen The monitor has been repaire An alternate method using the Westinghouse monitor was available to accomplish automatic action Additionally, the Nuclear Research Corporation radiation monitors continued to operate throughout this event as the Technical Specification required preplanned alternate monitoring method on the process vent release path, (Closed) LER 338/87-17, Rev. 1: Steam Generator Tube Rupture Responses will be tracked under the items identified in AIT report 338/87-24 dated August 28, 198 . -

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11 (Closed) LER 338/88-15, Rev. 0: RHR Pumps Not Tested During Steam Generator Tube Rupture Outage A station deviation report was submitted to notify the responsible department of the missed surveillsnce and to schedule it for the next time the unit is in Mode The ISI Pump and Valve program was reviewed to ensure there were no other missed surveillance This item is identified as a LIV (338/83-22-04) for failure to conduct a surveillance on schedule. Based on the licensee's corrective action and program this LER and LIV are close . Licensee Action on Previous Enforcement Matters (92702)

(Closed) Licensee Identified Violation (LIV) 338,339/87-19-17: Core Alteration Without A Charging Pump The licensee investigated this and similar instances where mode changes were made without taking proper actio This was investigated using the Human Performance Evaluation System (HPES) techniques. The licensee had developed mode change checklists to avoid these problems in the futur . Exit i The inspection scope and findings were summarized on August 19, 1988, with those persons indicated in paragraph The inspectors described the areas inspected and discussed in detail the inspection results listed below. The licensee did not identify as proprietary any of the material providad to or reviewed by the inspectors during this inspectio Dissenting comments were not received from the license <

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338/88-22-01 Inspector Followup Item (IFI) - Followup on the cause

of Unit 1 "C" main feedwater isolation failure to

fully close (paragraph 3) j 338/88-22-02 Violation - Failure to follow a containment entry procedure with three examples (paragraph 6)

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