IR 05000344/1987040

Insp Rept 50-344/87-40 on 871018-1121.Violations Noted. Major Areas Inspected:Operational Safety Verification,Maint, Surveillance & Event Followup

ML20237A970
Person / Time
Site:	Trojan File:Portland General Electric icon.png
Issue date:	11/30/1987
From:	Rebecca Barr, Mendonca M, Suh G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML20237A890	List: IR 05000344/1987040 IR 07100018/2011021 ML20237A888
References
50-344-87-40, NUDOCS 8712150371
Download: ML20237A970 (15)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION V

Report No: 50-344/87-40 ,

Docket No: 50-344 License No: NPF-1 Licensee: Portland General Electric Company 121 S. W. Salmon Street Portland, Oregon 97204 l

Facility Name: Trojan Inspection at: Rainier, Oregon I

Inspection conducted: October 38 - November 21, 1987 Inspectors: 7 ^\ N = - A c ~ "4" # 7 l R. C. Barr liate Signed Senior Resident Inspector

%% %dm e n n/s - /J'1 G. Y. Suh Date Signed Resident Inspector Approved By: Ah cA "N " A

fi~ M. Mendonca, Chief Date Signed Reactor Projects Section 1 Summary:

Inspection on October 18 - November 21, 1987 (Report 50-344/87-40)

Areas Inspected: Routine inspection of operational safety verification, raaintenance,' surveillance, and event follow up. Inspection procedures 30703, 61726, 62703, 71707, 71709, 71710, 71881, 73051, 90712, 92700, 92701, and 93702 were used as guidance during the conduct of the inspectio )

l Results:

Two violations were identified. (Failure to follow plant procedures -

paragraph 6; and, failure to perform required rod drop time measurements -

paragraph 6).

8712150371 871130 PDR ADOCK 05000344 G PDR

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DETAILS I Persons Contacted

• D.W. Cockfield, Vice President - Nuclear

• C.A. Olmstead, Plant General Manager R.P. Schmitt, Manager, Operations and Maintenance D.W. Swan, Manager, Technical Services J.K. Aldersebaes, Manager, Plant Modifications J.D. Reid, Manager, Plant Services A.N. Roller, Manager of Nuclear Plant Engineering R.L. Russell, Operations Supervisor R.H. Budzeck, Assistant Operations Supervisor D.L. Bennett, Maintenance Supervisor R.A. Reinart, Instrument and Control Supervisor T.O. Meek, Radiation Protection Supervisor 1 R.W. Ritschard, Security Supervisor C.H. Brown, Operations Branch Manager, Quality Assurance

• D.L. Nordstrom, Nuclear Engineer, Nuclear Safety and Regulation

• M.C. Singh, Manager Outage Planning and Scheduling The inspectors also interviewed and talked with other licensee employees during the course of the inspection. These included shift supervisors, reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, and quality assurance personne * Denotes those attending the exit intervie . Plant Status On October 18, 1987, the Troje.n facility was varying reactor power between approximately 80% and 90% power as ambient conditions permitted (limited by main condenser backpressure since only one of two of the circulating water pumps was operable). On October 20, 1987, pressurizer pressure transmitter, PT-455, failed (the third time in ten weeks)

requiring portions of the Reactor Protection System be tripped. On October 21, 1987, the reactor was shutdown due to control rod M-8 dropping from step 210 to step 72. The reactor was restarted on October 22, 1987, and returned to 90% power on October 23, 1987. On October 25, 1987, the West Circulating Water Pump was returned to service and reactor power increased to 100%. At 4:02 p.m. on October 26, 1987, reactor power was reduced to 90% to return to within the thermal limits (F delta H and F sub R) of technical specification 3.2.3.A.1. On October 29, 1987, follcwing the repair of PT-455, the calibration of nuclear instruments and incore flux mapping, reactor power was increased to 100%. On October t 30, 1987, steam generator pressure transmitters were found out of calibration, recalibrates and increased surveillance of these instruments implemented. On November 5, 1987, reactor power was reduced to 60% to repair a failing speed sensing device on the South Main Feed Pump. On Novembcr 6, 1987, power was returned to 100% where it remained through the remainder of the inspection perio ,

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3. Operational Safety Verification During this inspection period, the inspectors observed and examined activities to verify the operational safety of the licensee's facilit The observations and examinations of those activities were conducted on a daily, weekly or biweekly basi Daily the inspectors observed control room activities to verify the licensee's adherence to limiting conditions for operation as prescribed in the facility Technical Specifications. Logs, instrumentation, recorder traces, and cther operational records were examined to obtain information on plant conditions, trends, and compliance with regulation On occasions whan a shift tornover was in progress, tne turncver of information on plant status was observed to determine that all pertinent information was relayed to the oncoming shift personne Each week the inspectors toured the accessible areas of the facility to observe the following items:

(a) General plant and equipment condition (b Maintenance requests and repair (c Fire hazards and fire fighting equipmen (d Ignition saurces and flamable material contro (e) Conduct of activities in accordance with the licensee's administrative controls and approved procedure (f) Interiors of electrical and control panel (g) Implementation of the licensee's physical necurity pla (h) Radiation protection control (1) Plant housekeeping and cleanlines (j) Radioactive w6ste system i (k) Proper storcge of compressed gas bottle The inspectors examired the licensee's equipment clearance control weekly with respect to removal of equipment from service to determine that the licensee complied with technical specification limiting conditions for operation. Active clearances were spot-checked to ensure that their issuance was concistent with plant status and maintenance evolutions. Logs of jumpers, bypasses, caution and test tags were examined by the inepector l Each week the inspectors conversed with operators in the control room, and with other plant personnel. The discussions centered on pertinent topics relating to general plant conditions, procedures, security, training and other topics related to in-progress work activitie The inspectors examined the licensee's nonconformance reports (NCR) to confinn that deficiencies were identified and tracked by the syste Identified nonconformances were being tracked and followed to the completion of corrective actio '

Routine inspections of the licensee's physical security program were i performed in the areas of access control, organization and staffing, and I detection and assessment systems. The inspectors observed the access control measures used at the entrance to the protected area, verified the

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i integrity of portions of the protected area barrier and vital area {

barriers, and observed in several instances the implementation of compensatory measures upon breach of vital area barriers. Portions of the isolation zone were verified to be free of obstructions. Functioning .

of the central and secondary alarm stations, including the use of CCTV ,

monitors, was observed. On a sampling basis, the ir.spectors verified that ]

the required minimum number of armed guards and an individuals authorized ]

to direct security activities were on sit '

The inspectors conducted routine inspections of selected activities of the licensee's radiological protection program. A sampling of radiation !

work permits (RWP) was reviewed for completeness and adequacy of information. Diving the course of inspection activities and periodic i tours of plant areas, the inspectors verified proper use of personnel monitoring equipment, observed individuals leaving the radiation !

controlled area and sigc.ing out on appropriate RWP's, and observed the posting of radiation areas and contaminated areas. Posted radiation levels at locations within the fuel and auxiliary buildings were verified by the inspectors using both NRC and licensee portable survey meter The involvement of health physics supervisors and engineers and their awareness of significant plant activities was assessed through conversations and review of RWP sign-in record Tne inspectors verified the operability of selected engineered safety features. This was done by direct visual verification of the correct position of valves, availability of power, cooling water supply, system i integrity and general condition of equipment, as applicable. Systems f verified operable during this inspection period included portions of the High Head Safety Injection Syste No violations or deviations were identifie !

4. Maintenance Pressurizer pressure transmitter PT-455 failed high on September 12, 1987, failed again on September 14, and yet again on October 20. The !

inspectors observed the replacement (Maintenance Request MR 87-6514) of the transmitter that failed on October 20. Preliminary work included checks of the instrument loop for PT-455, various checks of the transmitter that feiled on October 20, and calibration and time response testing of i the replacement transmitter prior to installation. The inspectors ;

verified that the appropriate bistables were tripped upon detection of j the failed transmitte In a test (suggested by the pressure transmitter vendor) to determine if the instrument block valve was acting as a check valve that failed to relieve pressure at the transmitter, the transmitter was pressurized, using test equipment, to approximately 2400 psig, and the block valve was slowly opened. Pressure at the transmitter quickly decreased to system pressure, as designe The inspectors observed the electrical splicing performed in the l connection of the transmitter leads to the field cable leads. The !

installation procedure and shim and splice tubing sizes were varified to l

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be in conformance with the vendor installation guid Due to personnel I error, the transmitter to field cable connections were reversed. A nonconformance report NCR 87-403 was initiated which resulted in the ]

preparation of MR 87-6729 to correct the wiring reversal at the next shutdown or revise appropriate electrical drawings to reflect the as installed condition. A safety evaluation performed by Nuclear Plant Engineering concluded the wire reversal in no way affected the technical operation of the system. In order to place the transmitter in operation, j the leads were reversed at the Control Room cabine Radiation protection and quality control inspection coverage was presen ,

The QC inspector processed nonconformance report NCR 87-405 which dealt j with the jarring against the concrete floor of the digital multimeter i used in the calibration of PT-455 and nonconforming activity report NCAR i P87-142 which addressed the use of a micrometer which was not properly !

calibrated. The inspectors verified corrective actions had been implemente During installation of the replacement transmitter, the inspectors noted that the instrumentation and control technician removed the danger tag at the instrument block valve. This was confirmed to have been done prior to the release of the clearance by the clearance holder. Upon discussions with the individuals involved in the release of clearance number 87/2172, the inspectors concluded that the release of the danger tag at the instrument block valve through the use of a change of status was allowed by plant safety procedure PS-3-30, " Trojan Holdout and Tagging Procedure." In subsequent discussions with plant management, the inspectors questioned whether PS-3-30 provided adequate guidance especially with regard to activities performed by instrumentation and control technicians. Plant managemer,t committed to evaluate and clarify ;

the procedure with regard to tag remova ~

The licensee's continuing investigation into the cause of the multiple PT-455 failures was reviewed. Examination of failed transmitters by the licensee and by a vendor representative indicated that the mode of failure was physical damage to the transmitter strain gages and/or associated mechanical components. The cause of the physical damage was not identified at the time of the inspection. Two transmitters were returned to the vendor for detailed examination. As discussed above, a (

test to determine whether the instrument block valve was acting as a '

check valve was performed at the suggestion of the vendor. Licensee l engineers performed an inspection of piping geometry, adjacent air flow, i and transmitter installation. Telephone conversations with representatives of several other utilities and other industry contacts were conducted to obtain further information on experience with the failed transmitters. The inspectors concluded that the licensee's

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l inspection was comprehensive. Continued management attention appeared ;

necessary to assure that the cause would be identified and addressed in a f timely manne ;

In addition to the replacement of PT-455, the inspectors observed the i recalibration of two main steam line pressure transmitters, PT-524 and !

PT-544, during an October 30 event. This event is discussed in detail in !

the Event Followup section. The work was performed under maintenance

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request MR 87-6334. Two I & C technicians worked as a team to provide necessary double verification. Quality control coverage was observed to be present. The inspectors verified that the calibration process was curren Silicon grease and new 0-rings were used in reassembly of the I transmitters af ter recalibratio No violations or deviations were identifie l Surveillance

' The inspectors performed a limited inspection of chemistry related surveillance testing. The inspection included a review of the chemistry !

manual guidelines and instructions of selected procedures; observation of i surveillance tests to determine reactor coolant system dissolved oxygen, l chloride, and fluoride concentrations; dose equivalent iodine-131 {

activity level, and gross beta activity level; and discussions with chemistry technicians and supervisory personnel.

l In addition, the inspectors reviewed sampling and analyses schedules and completed sample logs to ascertain whether technical specifications surveillance requirements were met. In general, surveillance testing was performed at conservative frequencies during required operational conditions. The requirement of T.S. 4.0.4 to perform surveillance testing prior to entering the applicable operational mode for the limiting condition for operation was met either by performir.g the associated chemistry related surveillance test under all operating conditions or through the use of checkoff lists in General Operating l Instruction G01-1 which controls plant startup from cold shutdow The inspectors also reviewed completed sample logs to verify that measured levels were within T.S. required limits. The review included

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l records of primary coolant specific activity; primary coolant chemistry

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parameters; boron concentrations of the boric acid storage tanks, refueling water storage tank, and safety injection accumulators; and

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viscosity, water, and sediment measurements for the diesel fuel storage tank, diesel generator day tanks, auxiliary feedwater system diesel

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engine tank, and diesel fire pump tank. An independent calculation of dose equivalent iodine-131 levels verified that proper weighting factors were being used in the calculatio A specific area of review dealt with the requirement to perform iodine I isotopic analyses between two and six hours following a thermal power change exceeding 15 percent of the rated thermal power within a one hour period. Instructions have been provided to plant operetors in G01-5

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(Steady-State Operations and Load Changing), and on a yellow label affixed to the main generator Control Room panel to notify the chemistry department of changes exceeding 15 percent of rated power. The inspectors reviewed chemistry logs and verified that timely iodine isotopic analyses were performed after all plant trips, plant startups, and major power changes which have occurred since the 1987 refueling outage. Discussions with chemistry supervisory personnel revealed a high level of interest in this area. Further evidence of management attention in this area was obtained in a discussion with a plant chemist on the plant's program to

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evaluate iodine spiking in primary coolant. Using measured daily value trend plots of dose equivalent iodine-131, iodine-131, and cesium-138 l activity levels were being maintained. Review of the data indicated I relatively minor spiking factors following power transients. Dose equivalent iodine-131 levels were below 0.1 microcuries per gram and appeared to primarily be a result of the presence of tramp uranium. The trend plots clearly showed plant power levels and power transient histor General observations of laboratory conditions and operation were  ;

conducted. The inspectors noted that reagent containers were properly labeled with identification, preparation date, expiration date, and technician initials; storage of solvents were in areas below eye-level; l pipetting was not performed by mouth; and laboratory coats and eye protection were used as appropriate. Improvement in material conditions in the chemistry laboratory located inside the radiologically controlled l area appeared to be neede The inspectors noted that work benches and

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l hoods were in a cluttered state, and two trash receptacles were immediately below the emergency shower. The inspectors informed a

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l chemistry technician who placed the receptacles outside the emergency i shower area. The inspectors recommend increased management attention to improve laboratory material condition )

No violations or deviations were identifie )

6. Followup of Open Items Unresolved Item 50-344/87-37-01 (Closed): In a review of completed data sheets for plant periodic operating test P0T-28-1, titled " Core Quadrant Power Tilt Ratio Verification," the inspectors identified three instances where the steps specified in POT-28-1 for making a QPTR determination were apparently not followed per procedure. Calculations using power l range detector voltages. indicated a QPTR value greater than 1.020. Per l P0T-28-1, calculations using detector currents were required to be performed to verify the existence of an excessive QPTR value. Based on a review of records and discussions with licensee representatives involved i in the three instances, the inspectors concluded that the required detector current calculations were apparently not performed. This is an apparent violation (50-344/87-40-01). Item 87-37-01 is considered administratively closed. PGE should include in their response to the notice of violation the concerns of 87-37-0 From discussions with licensee personnel who performed P0T-28-1 surveillance tests of September 12, September 19, and September 26, the inspectors determined the following: the operators who performed the surveillance generally performed a number of actions and showed a high level of interest in response to indicated values of QPTR exceeding 1.020; the procedure, POT-28-1, was evidently considered and evaluated in detail; the cognizant engineer.was consulted and a number of actions were performed to verify that an actual excessive QPTR did not exist. For example, primary coolant hot and cold leg temperature differences were verified to meet channel check requirements; the absence of misaligned  !

rods was verified; and low levels of individual channel currents at which

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electronic noise or normal process variation could lead to incorrect QPT i

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values were identified. In addition, engineering personnel had available data including results of flux mapping and in-core thermocouple readings which indicated that QPTR was within allowable value The operators and plant engineering apparently failed, however, to follow the procedural requirements of POT-28-1 without processing a procedural deviation per plant administrative order A0-4-4, titled " Changes." The inspectors noted that a deviation had not been processed on three separate instances involving three different operating crews as well as plant engineering. The inspectors considered this apparent violation clearly indicated that concerns on procedural adherence and awareness of procedural requirements are not based on isolated occurrences and deserve increased management attentio Related procedural adequacy concerns noted in this inspection period are discussed in the " Maintenance" and

" Event Followup" section Unresolved Item 50-344/87-37-03 (Closed): In a review of technical specification surveillance requirements, the inspectors identified apparent discrepancies with regard to T.S. 4.10.1.2, which requires that the rod drop time of each full length rod not fully inserted be verified to be less than or equal to 2.2 seconds within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to reducing the shutdown margin to less than the limits of T.S. 3.1.1.1. Following discussions with licensee representatives and review of test documentation, the inspectors concluded that the requirements of .10.1.2 were apparently not met in low power physics testing conducted for fuel cycles 6, 7, and 8. This is an apparent violation l (50-344/87-40-02).  ;

For these cycles, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to reducing the shutdown margin

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to below the limits of T.S. 3.1.1.1, the reactor was manually tripped.

l followed by measurement of the rod drop time of only one control rod at location K-06. This measurement was conducted as part of low power physics testing per plant periodic engineering test procedure PET-13- Rod drop time measurements per plant periodic instrument and control test procedure PICT-16-1, titled " Hot Rod Drop Time Measurements," were apparently not conducted within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time requirement. The licensee has recently submitted a Licensee Change Application (LCA) 153 1 which will allow credit for the performance of PICT 16-1 rod drop time tests within a seven day period to satisfy the requirements of technical specifications 4.10.1.2. The inspectors' review of test documentation was limited to Cycle 6 to the present. Records for testing in cycles earlier than Cycle 6 were not reviewed. Open Item 87-37-03 is considered administratively closed; however, the licensee should address all concerns of this open item in the response to the notice of violatio . Follow-up on Licensee Event Reports (LER)

(a) LER General Comments A previous issue has been the thoroughness of event evaluation and follow-up. The licensee responded by implemer. ting an internal event reporting system and a performance monitoring and event evaluation group. This response has resulted in improved event evaluation and cause determination. The remaining weakness yet to be resolved is e

effective and timely implementation of corrective actions such that !

similar events have a low probability of recurring. In reviewing 1 the first thirty LER's of 1987, recurring events associated with j troubleshooting, Control Room integrity, missed surveillance and j excessive leakage from systems outside containment which could {

contain radioactive water following a design basis accident, are 1 indicative of either ineffective or untimely corrective action implementation. This issue will be followed as Open Item j 50-344/87-40-03. Specific LER's are discussed below.

(b) LER Evaluation I LER 87-02 (Closed) Control Room Boundary Door Stuck Open - ,

Insufficient Control Room Positive Pressure Maintenance. The '

inspectors verified after the completion of the repair and !

event evaluation that the Control Room viewing gallery door was operable. Additionally, the inspectors noted that the work j instructions provided the craftsman did not require metal j screws vice wood screws for seal cartridge installatio Implemented corrective actions did not address the quality of work instructio j LER 87-03/87-03, Revision 1 (Closed) Inadequate Response Time Testing !

(RTT) - The inspectors verified the surveillance procedures i associated with RTT for the auxiliary feedwater pumps and l containment cooler fans had been revised. The licensee has i also evaluated other response time tests for correctnes LER 87-04 (Closed) Technician Error Resulted in Reactor Trip Breaker Opening - The inspectors verified procedure PICT 10-1 had been rev1 sed to reflect the need to use care when exiting ,

the procedure prior to its completion. The need for operators l to effectively communicate the urgency of events and control i evolutions that are off-normal or extraordinary was not addressed in the licensee's corrective action j LER87-05(Closed) Waste Gas Compressor (WGC) 0xygen Alarm i Inadvertently Disconnected from Control Room - The inspectors :

verified the WGC oxygen alarm was returned to service. The l licensee conducted an independent review of the temporary modification system that resulted in the recommendation to clerify technical specification 3.3.3.11 and a change to Administrative Order 6-2 requiring review of open Temporary Modifications prior to working a design change packag Corrective actions did not address operations control of plant maintenance activitie LER 87-06/87-06, Revision 1 (Closed) Deficiencies in Flood Protection Design Provisions - Flood Protection design is being evaluated by Nuclear Reactor Regulation. By September 30, 1987, the licensee committed to implementing a preventive maintenance precedure that would periodically inspect flood protection design features. The procedure is yet to be implemente i

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-9 LER87-10(Closed) Inadvertent Actuation of 230KV Differential Relay - Partial Less of Off-Site Power. The inspectors assessed the event report, Performance Monitoring and Event Analysis report and the Plant Review Board evaluation. Corrective actions were implemented to specifically address this event and previous events resulting from work performed in the switchyar However, the corrective actions did not generically address troubleshooting problem LER87-11(0 pen) Electrical Penetration Leakage due to Degraded s Seal Penetration /E-107 - The event review has not identified the cause of the seal degradation. The inspectors verified the local leak rate testing of the electrical penetrations was within design requirement LER 87-13/87-13 Revision 1 (Closed) Accumulator Fill Line Rupture '

- The inspectors provided detailed comments in IR 87-18 and 87-2 The licensee has amended criteria for posting and removing QC ,

hold tags. Operators have been counselled on deliberate, controlled and conservative operation that includes compliance i to procedure l

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LER 87-14/87-14, Revision 1 (Closed) Charging Pump Cladding Corrosion - The inspectors observed the replacement of the i charging pumps. They also reviewed design calculations that

verified newly established flow rates that were consistent with design assumption LER 87-15 (Closed) Steam Generator (S/G) Level Transmitters Improperly Calibrated - The inspectors observed the recalibration of a S/G level transmitter and reviewed the data of all the S/G level transmitter calibrations. The licensee's corrective actions failed to address why the calibration procedure did not provide adequate direction to the technician on how to perform the calibration. The procedure was revised to include the requirement of draining the transmitter prior to calibratin LER 87-16 (Closed) Reactor Trip Breakers Opened Due to Procedure -

Deficiency - The inspectors observed the event during its occurrence and verified that commitments to procedural revisions were made. Implemented corrective actions did not address deficiencies in control of complex evolutions. This event is discussed in Inspection Report 87-2 LER 87-17 (0 pen) Control Room Penetrations Leaking - The inspectors verified procedural changes committed to in the LER were implemente The licensee review did not address the situation where operation of CB-13 would be required during Control Room pressurization. The licensee believes that the Control Room -

Cable Spreading Room sealing is sufficient to permit operation of CB-13 with the Control Room pressurized, but adequate justification for this conclusion was not prioritized in the )

event evaluatio I

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LER 87-18 (Closed) Valve Packing Leakage Exceeding FSAR Assumed Leakage - The inspectors walked down those portions of systems outside of containment that could carry radioactive fluid during a design base loss of coolant accident. No leakage in excess of 1580 cc/hr was identified. The inspectors also reviewed a portion of the leak rate tests conducted on these systems. Finally, the licensee, as a result of the leaking Boron Injection Tank relief valve event of September 28, 1987, has conducted training to alert staff of the importance of minimizing leakage from these system LER 87-19 (Closed) Movement of Irradiated Filter Near Radiation Monitor - Resulting in Containment Ventilation Isolation - The licensee comitted to revising procedures. The inspectors verified the procedural changes had been mad LER 87-20 (Closed) Seismic Monitoring Instrumentation Surveillance Missed Due to Inadvertent Deletion From Schedule LER 87-27 (Closed) Boron Injection Relief Valve Leaked Greater Than FSAR Assumed Limits - The licensee conducted training to alert staff of the significance of leakage in systems external to containment. Additionally, operators have been instructed to specifically evaluate identified leaks against the FSAR.

I No violations or deviations were identifie . Event Followup (a) Steam Generator Preesure Transmitters Calibration Drift On October 30, 1987, with the plant at approximately 90 percent power, the licensee's investigation of main steam line pressure transmitter indications revealed that all 12 transmitters were indicating lower than actual system pressure by 35 to 50 psi. This was determined by performing applicable portions of the calibration ,

procedure to one of the pressure transmitters on "C" main steam line j and by comparison to other steam line pressure indicators. All 12 '

steam line pressure indicators had passed recent channel check The investigation was a result of operators' observations that lower than expected steam pressures were being indicated in the Control Roo The licensee's immediate actions included the following. Safety system setpoints were reviewed to determine the effect of lower than actual indicated steam pressure. The effect was determined to be conservative in all cases where steam line pressure signals were used in the Reactor Protection System except for the reactor trip signal of low steam generator level coincident with steam /feedwater flow mismatch. Analyses performed by plant and corporate engineers determined that technical specification allowable setpoints were still met given the magnitude of the indicated error. Steam pressure was also determined to be an input into the auxiliary

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4 feedwater pump differential pressure controllers. All auxiliary ;

feedwater control values were adjusted to the full open position, '

and subsequent analyses by corporate engineering showed on a preliminary basis that FSAR required minimum auxiliary feedwater flow would not have been assured with the control valves in their throttled positions. A report to the NRC operations center was made in a timely manner. The twelve transmitters were recalibrates. Upon completing recalibration, the auxiliary feedwater control valves were returned to their throttled positions. During the event, plant management briefed the resident inspectors on the scope and status of activitie On a continuing basis, the licensee instituted a program to assure that indicated steam line pressures would remain functional. The program included, (1) the installation of a high accuracy pressure inaicating gauge on the "A" steam line drain line which was compared once a shift to Control Room indications, and (2) an increased frequency of calibration of the permanently installed steam line pressure transmitters (initially a daily calibration check of one transmitter).

The licensee's investigation of the cause of the transmitters being out of calibration included bench tests on spare transmitters, review of equipment history files and calibration sheets, review of the calibration process, and consultations with the vendor. Three vendor representatives arrived on site the week following the event to assist in the investigation. The licensee's Performance Monitoring and Event Analyses group has also begun as investigation into the even The inspectors reviewed immediate licensee actions and observed the recalibration of several pressure transmitters. The licensee had reviewed applicable technical specification requirements in j developing its response to the problem. Coordination between plant staff and corporate support groups was evident. The inspectors recommend continued utility management attention to assure that plant events receive timely and adequate attention from the Nuclear j Plant Engineering and Nuclear Safety and Regulation department i The inspectors also reviewed the calibration data sheets for the steam line pressure transmitters which revealed that 11 of the 12 transmitters were calibrated initially by the same technician in a two day period. All 12 of the steam line pressure transmitters were ,

installed during the 1987 refueling outage. In addition, the inspectors verified that the auxiliary feedwater control valves were returned to their throttled positions following recalibration of the steam line pressure transmitters. The licensee's continuing activities will be reviewed in the followup of Open Item 87-39-0 .

(b) Partially Dropped Control Rod With the plant in Mode 1 at 80% power on October 21, 1987, the control rod at location M-8 in control bank D dropped approximately 100 steps to 70 steps during automatic control rod movement. The operators immediately placed rod control in manual and reduced turbine load to reduce power mismatch. An NRC inspector was in the control room during the event and observed the following activities performed by the operating crew and members of plant management, maintenance, and engineering, who arrived in the control room shortly after the occurrence of the dropped rod. The control rod at location M-8 was confirmed to have dropped by performing a system check of the digital individual rod position indicatiun system and by observing expected changes in quadrant power tilt ratio and axial flux difference. A flux map using the in-core moveable detectors was initiated to obtain further data of core parameter Initial troubleshooting by instrumentation and control personnel did not reveal electrical problems in the control rod drive power cabineth An attempt to raise control rod M-8 was unsuccessful, and the rod fell an additional 12 steps in the attempt. The licensee concluded that the control rod was trippable and postulated that the cause of the dropped rod was an electrical problem in the movable gripper assembly circuitry. An open circuit in the movable gripper coil, cabling or connectors inside containment was suspecte Licensee managem6nt made the decision to shut down the plant in order to effect repair Subsequent troubleshooting identified the cause of the dropped rod to be a failed diode in the movable gripper coil circuitry. The diode was replaced, and the plant was restarted the following da The inspectors observed operators referring to off-normal procedures, performing quadrant power tilt ratio measurements and logging of axial flux difference penalty points. Applicable technical specification action statements, including a reduction to 75% power, were performed in a timely manne Emergency procedures were reviewed to verify that the radiological emergency response plan need not be entere The inspectors questioned plant management in the Control Room on the deportability of the event. The event was determined to be r.ot reportable since the decision to shut down the plant was a voluntary one and was not forced by technical specification requirements. The inspector reviewed the applicable technical specifications and concluded the plant could have remained at power in Mode 1 and could have met applicable T.S. action statements in a timely manner. In a subsequent discussion with plant management, the inspectors discussed " courtesy" ENS reports made for events in which there is some doubt as to deportability. In a November 2 memorandum to the operations department, the plant manager provided instructions for making ENS reports on an information basis for plent events whlch s l cause entry into technical specification action statements and for I which deportability requirements are unclea <

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In the review of licensee actions in response to the dropped rod I event, the inspectors discussed with licensee representatives the manner in which adequate shutdown margin per T.S. 3.1.1.1 was confi rmed. The determination of shutdown margin was required by T.S. 3.1.3.1 as one action in response to the dropped rod. During the event, the operations crew compared control rod positions with the control rod insertion limits as shown on recorder ZR-41 Operating Instruction 01-11-8, titled " Shutdown Margin", specified that when the control rods were at or above the insertion limits, the shutdown margin requirements were met. 01-11-8, however, did ,

not address the case of a dropped rod being below the bank insertion limit with the rest of the bank being above the limit. During the .

event, the operations crew consulted the engineering department to i confirm that adequate shutdown margin existed. The inspectors ;

understood that with the reactor operating above its rod insertion limits followed by a dropped rod event, adequate shutdown margi .

would normally be expected to remain as either power defect and/or !

withdrawal of the controlling bank compensated for the dropped ro !

There could be instances,-however, where this may not be the cas !

For instance, with the reactor operating with its controlling bank at the rod insertion lioit with rod control in manual, a dropped rod event may result in inadequate shutdown margin if turbine load was i not reduced to eliminate power mismatch. The inspectors discussed the adequacy of Section .3.1 of 01-11-8, which dealt with the case of a critical reactor with all rods trf ppable, with the cognizant engineer. The cognizant engineer committed to revise 01-11-8 as appropriate to address the dropped rod case. The inspectors believe-this to be another instance where the adequacy of plant procedures needs to be improved. As discussed in the " Maintenance" section, this inspection also indicated that the clearance procedure PS-3-30 could be improve (c) Nuclear Enthalpy Rise Hot Channel Factor Exceeded At 4:02 p.m. on Monday, October 26, 1987, after performing in-core flux mapping, the licensee determined T.S. 3.2.3. (Fr - Nuclear Enthalpy Rise Hot Channel Factor) was exceeded. At 4:14 reactor power was reduced to 90%. Shortly, thereafter, the licensee verified the power reduction to 90% restored Fr to within limit The reactor remained at 90% power until changes in core power distribution allowed an increase to 100% power at 2:37 a.m. October 30, 1987. Immediately after achieving 100% reactor power, the licensee verified through in-core flux mapping that Fr was within limit ,

The licensee believes that exceeding Fr was due to the mirror image exchange of eight specially designed periphery fuel assemblies, that had been resident in their previous core location for five cycles, and the inability to predict with high accuracy the fuel burnup of those assemblies. The licensee has not yet determined if the extended operation at reduced power levels contributed to exceeding F .

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The inspectors examined the data from various in-core flux maps and i concluded Fr limits had been exceeded. The inspectors could not ,

conclude exact length of time the Fr limit had been exceeded; however, conservative estimates indicate Fr may have been exceeded for up to thirty-two hours. The inspectors noted 100% power was initially achieved for the current fuel cycle at 7:50 a.m. on October 25, 1987, but an assessment of Fr was not performed until the afternoon of the following day. The inspectors also noted that Reload 10 design report predicts operation close to Fr limit On October 16, 1984, NRC issued Generic Letter 84-21, "Long Term Low Power Operation in Pressurized Water Reactors," to alert utilities of the potential for an unreviewed safety question resulting from extended low power operation. The licensee responded to the Generic Letter by implementing procedural changes, recommended by Westinghouse, to operate within the axial offset expected at full power. The licensee was operating with this guidance following the extended operation at low powe In a November 19, 1987, meeting the licensee committed to providing the inspectors a detailed evaluation stating the cause of exceeding the Nuclear Enthalpy Hot Channel Factor limit. This issue will be followed as Open Item 50-344/87-40-0 The inspectors concluded that once the licensee recognized the Fr limit was exceeded, the licensee respended per technical specification requirement No violations or deviations were identifie . Exit Interview The inspectors met with the licensee representatives denoted in paragraph 1 on November 19, 1987, and summarized the scope and findings of the inspection activitie _ _ - _ _ - - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ -