IR 05000333/1985025

Insp Rept 50-333/85-25 on 850901-1011.No Violation Noted. Major Areas Inspected:Action on Previous Insps,Ler Review, TMI Task Action Plan Items II.F.1.6 & III.D.1.1 & Operational Verification

ML20136H607
Person / Time
Site:	FitzPatrick
Issue date:	11/14/1985
From:	Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20136H573	List: IR 05000333/1985025 ML20136H567
References
TASK-2.F.1, TASK-3.D.1.1, TASK-TM 50-333-85-25, NUDOCS 8511250143
Download: ML20136H607 (11)

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U.S. NUCLEAR REGULATORY COMMIdSION

REGION I

DCS Numbers 50333-850301 50333-850725 50333-850905 50333-850820 Report No. 85-25 Docket No. 50-333 License No. DPR-59 Priority -- Category C Licensee: Power Authority of the State of New York P.O. Box 41 Lycoming, New York 13093 Facility Name: J. A. FitzPatrick Nuclear Power Plant Inspection At: St.riba, New York Inspection Conducted: September 1 - October 11, 1985 Inspectors: A.J. Luptak, Resident Inspector J.R. Stair eactor Engineer, DRP 2C Approved by: MMM

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Date e'actorProject{Section2C Inspection Summary:

Inspection on September 1 - October 11, 1985 (Report No. 50-333/85-25)

Areas Inspected: Routine and reactive inspection during day and backshift hours by one resident inspector and one region based inspector (143 hours0.00166 days <br />0.0397 hours <br />2.364418e-4 weeks <br />5.44115e-5 months <br />) of

. licensee action on previous inetction findings, licensee event report review, operational safety verification, surveillance observations, maintenance obser-vations, Hydrogen Water Chemistry test, TMI Task Action Plan item followup, and review of periodic and special report Results: No violations vere identified in the areas inspected. Issues discussed included the number of recent personnel errors noted in the past several inspec-tion reports in addition to those in paragraphs 2.c and 4.a, and the timeliness of the review of- the Component Quality Assurance Category List (paragraph 3.b).

8511250143 851118 PDR ADOCK 05000333 PDR

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DETAILS Persons Contacted

• R. Baker, Technical Services Superintendent

• R . Converse, Resident Manager

• Fernandez , Superintendent of Power

• J. Flaherty, Acting Instrument and Control Superintendent

• M. Hansen, Plant Engineer

• D. Lindsey, Operations Superintendent

• R. Liseno, Maintenance Superintendent E. Mulcahey, Radiological & Environmental Services Superintendent

• R. Patch, Quality Assurance Superintendent

• D. Simpson, Training Superintendent

• V. Walz, Assistent Technical Services Superintendent The inspector also interviewed other licensee personnel during this inspec-tion including shift supervisors, administrative, operations, health physics, security, instrument and control, maintenance and contractor personne * Denotes those present at the exit intervie . Licensee Action on Previous Inspection Findings -

(Closed) Inspector Followup Item (85-02-03) The licensee determined that the main cause of the turbine trip was a closed root valve in the sensing line to the pressure transmitter which supplies a pressure signal to the power / load unbalance circui This valve has since been placed on the valve lineup list to assure that it is kept open to prevent a future re-currence. Other balance of plant systems with root valves which have the potential to cause reactor trips have also been identified and placed on a valve lineup lis In addition, the licensee incorporated a modification to the power / load unbalance circuitry which would prevent a turbine trip if a similar mal-function occurred during a logic tes The inspector had no other questions regarding this ite . L'icensee Event Report (LER) Review The inspector reviewed LER's to verify that the details of the events were clearly reported. With the exceptions noted below, the inspector deter-mined that reporting requirements had been met, the report was adequate to assess the event, the cause appeared accurate and was supported by details, corrective actions appeared appropriate to correct the cause, the form was complete and generic applicability to other plants was not in questio . .

LERs 85-08-1, - 85-20*, 85-22*, and 85-23* were reviewe *LER's selected for onsite followu LER 85-22 reported a reactor trip on high reactor pressure due to the closure of the inside containment "B" Main Steam Isolation Valv Details of this event are discussed in paragraph 6.c. of Inspection No. 50-333/85-2 LER 85-20 reported the automatic isolation of High Pressure Coolant Injection System due to high ambient temperatures in the area of a steam leak detection sensor. The high temperature was caused by securing normal Reactor Building Ventilation for maintenanc It was noted that the date of the letter transmitting the LER and the report date of the LER did not agree, and that the LER was submitted several days late. The inspector reviewed LERs submitted in the past year for timeliness and determined that this was an isolated cas These items were discussed with the license The LER noted that a review of the temperature data during the Summer of 1985 for the "A" Residual Heat Removal (RHR) heat exchanger room (where the sensor is located) showed the normal temperature often exceeded 120 degrees The expected maximum ambient temperatcre for the Reactor Building, based on previous data, was 100 degrees The licensee was asked if any consideration was given to the effect this increased temperature may have on any equipment in this area which might fall under the Environment Qualification (EQ) program (10 CFR 50.49). The licensee's initial reponse was that none of the equipment in these areas is under the EQ program. After further questioning by the inspector, the licensee initiated a review for EQ consideration of the equipment in these area The inspector noted that, as a minimum, the leak detector sensors themselves should be included in the EQ program. The licensee agreed and stated that the detectors were qualified for the drywell atmosphere, which has a t normal temperature of 130 degrees ' The inspector verified this by reviewing the modification package which covered the installation of the detectors and the EQ report. However, the inspector noted the newly installed temperature detectors had not been added to the li-censee's EQ list. The licensee stated that they were still in the process of reviewing the modifications completed during the outage which ended in early June 1985, to verify the accuracy of this EQ lis At the close of this inspection period, the licensee was in the pro-cess of determining the effects of the higher temperatures on equip-ment located in these areas and updating the EQ list. The licensee also stated a step will be added to the procedure which controls

modifications to ensure any equipment installed, which is covered i under the EQ program, is added to the EQ lis This item is

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unresolved pending the completion of the licensee's revie (50-333/85-25-01).

While _ attempting to determine if any equipment in the RHR heat ex-changer room required EQ consideration, the inspector noted that the licensee's Component Quality Assurance Category List ("Q" List) con-tained conflicting information regarding the QA classification of components for the RHR heat exchanger vent valves, 10 M0V 166 A and B and 10 MOV 167 A and The "Q" list identified the electrical valve operators as Q. A. category IE and the circuit breakers for B-vent valve motors as category 1. The circuit breakers for the A vent valve motors, all four valve motors, and the mechanical valves them-selves were not considered category 1. These discrepancies were dis-cussed with the QA Superintendent, who initiated the " Procedure for Establishing Quality Assurance Category Classification," EDP-12, for the valves in questio The inspector also noted that in correspondence JPN 82-31, dated March 19, 1982, related to TMI Task Action Plan item II.B.1, the li-censee referred to these as safety-related valves. In addition, the inspector reviewed past Work Requests for maintenance which was per-formed on these valves. There have been only several minor main-tenance actions performed on these valves and in all cases except one they were considered Q.A. category II. The licensee has committed,

, pending the outcome of classification, to review the work performed on these valves and consider any appropriate actions. In addition, the licensee will review the QA category list for any other obvious inconsistencies. This item is unresolved pending the outcome of the licensee classification procedure (50-333/85-25-02).

The inspector reviewed NRC inspection report 50-333/84-11 which raised concerns about the completeness and accuracy of the "Q"-list. The licensee addressed these concerns in their letter JPN 84-42, dated June 29, 198t (response to Generic Letter 83-28) in which they com-mitted to review the list for compl?.teness and accuracy by December 31, 1985. The licensee informed the inspector that a detailed review

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of the compitte list has not been conducted. However, the licensee has been working on a comprehensive Planned Maintenance Program of which the first step is to generate a Master Equipment List (MEL). A consultant will be used to review the "Q" list for completeness and accuracy, and to generate a MEL which will contain, in addition to classification, information about each component (e.g. nameplate data, location, reference drawings, technical manuals, etc.) The licensee expects the MEL to be completed by the late summer of 1986 and will be revising their commitment dat c. LER 85-23 reported the inadvertent start of the A and C Emergency Diesel Generators while conducting a low Pressure Coolant Injection Subsystem Logic surveillance test. The diesel activation was initi-ated when an operator removed a test switch which was blocking the

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E diesel start signal prior to resetting the logic for a simulated high drywell pressure and low reactor water level. These steps were per-formed out of sequence when the operators were attempting to redo a previous step which had faile The inspector concluded that the operator directing.the surveillance test had determined the appropriate actions to take to first complete the portion of the test in progress and then reperform the steps which had failed. .However, as a result of poor communications, another operator removed the test switch before the individual direc-ting the test could reset the logic as specified in the procedur The inspector noted and discussed with the licensee that the LER did not provide a sufficiently detailed discussion of the occurrence, and reported only that the operator was reading ahead in the proce-dure and removed the test jack in anticipation of the next step. The licensee acknowledged the inspector's comments but did not feel a revised LER was require . Operational Safety Verification Control Room Observations Daily, the inspectors verified selected plant parameters and equip-ment availability to ensure compliance with limiting conditions for operation of the plant Technical Specification Selected lit an-nunciators were discussed with control room operators to verify that the reasons for them were understood and corrective action, if re-quired, was being take The inspectors observed shift turnovers biweekly to ensure proper control room and shift manning. The in-spectors directly observed the operations listed below to ensure adherence to approved procedures:

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Actions following the trip of the "A" Recirculation Pump Motor Generator on September 26, 198 Routine power operation Issuance of RWP's and Work Request / Event / Deficiency form On September 26, 1985, the "A" Recirculation Pump Motor Generator (MG) set was inadvertently tripped while the plant was at full powe The inspector was in the control room when this occurred and observed the operator response to the event including restart of the MG se Based on these observations, the inspector determined tne operator's actions were proper and in accordance with approved procedures and that the Technical Specification requirements were me The MG set was tripped when I&C technicians were attempting to iden-tify the cause of an automatic lock-up of the scoop tube positioner in the "A" MG set flow control circuit. After properly identifying

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which contacts to verify using the controlled diagram, the techni-cians failed to physically locate the correct contacts and shorted across contacts, which tripped the MG set field breaker, thus causing the "A" MG set to trip. The licensee later determined that the scoop tube positioner lock-up was caused when the relay, which senses an undervoltage condition on the 4160 V supply to the MG set, was removed by other I&C technicians during protective relay testing. Although previous testing had been performed at power (testing frequency is once per cycle), the plant was running with both scoop tubes already locked-up due to power swings. A critique of the event was held and corrective actions proposed are under plant management revie No violations were identifie Shift Logs and Operating Records Selected shift logs and operating records were reviewed to obtain information on plant problems and operations, detect changes and trends in performance, detect possible conflicts with Technical Specifications or regulatory requirements, determine that records are being maintained and reviewed as required, and assess the effective-ness of the communications provided by the log No violations were identifie c. Plant Tours During the inspection period, the inspectors made observations and conducted tours of the plant. During the plant tours, the inspectors conducted a visual inspection of selected piping between containment and the isolation "alves for leakage or leakage paths. This included verification that manual valves were shut, capped and locked when required and that motor operated valves were not mechanically blocke The inspectors also checked fire protection, housekeeping / cleanliness, radiation protection, and physical security conditions to ensure compliance with plant procedures and regulatory requirement No violations were identifie d. Tagout Verification The inspector verified that the following safety-related protective tagout records (PTR's) were proper by observing the positions of breakers, switches and/or valve PTR 851459 on the "A" Residual Heat Removal Syste PTR 851487 on the "B" Standby Liquid Control System.

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PTR 851556 on the "A" Low Pressure Coolant Injection Independent Power' Supply Syste No violations were identifie Emergency System Operability The inspector verified operability of the following systems by ensur-ing that each acce sible valve in the primary flow path was in the correct position, by confirming that power supplies and breakers were properly aligned for components that must activate upon an initiation signal, and by visual inspection of the major components for leakage and other conditions which might prevent fulfillment of their func-tional requirement Core Spray Syste Standby Liquid Control Syste Emergency Diesel Generator Fuel Oil and Air Start System No violations were identifie . Surveillance Observations The inspectors. observed portions of the surveillance procedures listed below to verify that the test instrumentation was properly calibrated, approved procedures were used, the work was performed by qualified person-nel, limiting conditions for operation were met, and the system was cor-rectly restored following the testing:

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F-ST-2H LPCI Subsystem Logic System Functional Test, Revision 12, dated April 17, 1985, performed September 5, 198 F-ST-IL Main Turbine Control Valve Instrument Channel and Valve Operability Check, Revision 12, dated August 8, 1984, performed September 25, 198 F-ST-1E Main Turbine Stop Valve Limit Switch Instrument Functional Test, Revision 4, dated April 19, 1983, performed September 25, 198 F-ISP-15 Drywell Equipment Drain Sump Flow Loop Functional Test /

Calibration, Revision 11, dated May 23, 1984, performed September 4 and 5, 198 F-ISP-16 Drywell Floor Drain Sump Flow Loop Functional Test /

Calibration, Revision dated May, 1984, performed September 4 and 5, 1985.

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Instrument and Surveillance Procedure (ISP) 15 and 16 are identical since i the flow loops are the same for both the equipment and floor drain sumps.

Each procedure contains both the functional test and calibration procedur . .

While observing the quarterly calibration of these instruments, the in-spector determined that performance of the procedure as written did not require a functional _ test of the entire flow loop. Therefore, when the quarterly calibration is performed, the components are removed and cali-brated, but the required monthly functional test will not be complete The note directing technicians not to perform the functional test portion of the procedure was added in a change made on May 23, 1984. A review of quarterly calibrations performed after the change indicated inconsistencies since some technicians did perform these functional test steps as required-in the procedural not The inspector asked the licensee why, although technically correct, the individuals performing these surveillance tests i failed to follow the procedures as written and did not consult supervisors to resolve the issue.

The inspector reviewed other surveillance procedures which contain both a functional test and a calibration procedure, and determined that the dis-crepancies noted in ISP 15 and 16 were isolated cases. The licensee also conducted a random review of surveillance procedures and found no discre-pancies. The licensee agreed to change ISP 15 and 16 to ensure that the functional tests were conducted. The inspector will review the changes made to ISP 15 and 16 for their adequacy in a subsequent inspectio (50-333/85-25-03)

The inspector also witnessed all aspects of the following surveillance test to verify that the surveillance procedure conformed to technical specification requirements and had been properly approved, limiting con-ditions for operation for removing equipment from service were met, testing was performed by qualified personnel, test results met technical specification requirements, the surveillance test documentation was re-viewed, and equipment was properly restored to service folloving the tes F-ST-90 EDG Inoperative Test / Loss of 115 KV Reserve Power / Loss of Station Battery, Revision 8, dated March 20, 1985, performed October 10, 198 No violations were identifie . Maintenance Observations The inspector observed portions of various safety related maintenance activities to determine that redundant components were operable, these activities did not violate the limiting conditions for opera-tion, required administrative approvals and tagouts were obtained prior to initiating the work, approved procedures were used or the activity was within the " skills of the trade," appropriate radiologi-cal controls were properly implemented, ignition / fire prevention con-trols were properly implemented, and equipment was properly tested prior to returning it to service, During this inspection period, the following activities were observed:

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WR 11/34737 on repacking "B" Standby Liquid Control Pum PMWR 10/02378 on disassembly and overhaul of the limitorque motor for the "A" Residual Heat Removal Pump Suction Valve for shutdown coolin .

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WR 71/37420 and 71/37529 on troubleshooting "A" Low Pressure

! Coolant Injection Independent Power Suppl No violations were identifie . Engineered Safety Feature (ESF) System Walkdown The inspector verified the operability of the selected ESF system by per-forming a complete walkdown of accessible portions of the system to con-firm that system lineup procedures match plant drawings and the as-built configuration, to identify equipment conditions that might degrade perfor-mance, to determine that instrumentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriat Standby Gas Treatment System No violations were identifie . Hydrogen Water Chemistry Test Hydrogen Water Chemistry control (HWC) is a method being explored by BWR owners to control the orvgen content in the reactor coolant, and therefore reduce or eliminate Intergranular Stress Corrosion Cracking (IGSCC) in reactor coolant piping and components. The licensee, in conjunction with General Electric (GE), conducted a test to determine its feasibility for use at this plant. Although this test has been run at other sites, a plant specific test was required to determine the appropriate injection rate and the radiation effects for this sit s The test was conducted in two phases: a three day mini-test and a Constant Extension Rate Technique (CERT) test. During the mini-test portion, the hydrogen injection rate was increased in incremental steps while chemistry, radiation, and various operating data was recorded. A hydrogen injection rate of approximately 12 SCFM was found sufficient to inhibit IGSCC. This rate is significantly less than that required at other plant The CERT test is a stress corrosion cracking test used to verify that the hydrogen addition rate will prevent IGSCC. Two test specimens are placed under stress in autoclaves with actual reactor coolant flow. Under normal chemistry conditions, the specimen failed from IGSCC in about 4 days as expecte In a HWC environment, the specimen is expected to fail in about 2 weeks, due to mechanical failure. At an injection rate of 12 SCFM, the test specimen failed slightly prematurely, in about 10 days. A decision

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g was made to rerun the CERT test at a higher hydrogen injection rate to create a larger amount of excess hydrogen in the coolant. GE is currently analyzing the data and specimens, and will present their findings and re-commendations to the licensee in late Octobe The . inspector reviewed the Safety Evaluation Report, test procedures and operating procedures for adequacy, conducted a walkdown of the system, observed portions of the test, and discussed radiological precautions with the license No violations were identifie . TMI-Task Action II.F.1.6 Containment Hydrogen Monitor System (CHMS)

In letter number JPN-82-91, dated December 23, 1982, the licensee stated that this modification would be completed during an outage scheduled to begin in May 1983. Based on information supplied by the licensee in letter

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number JPN-83-38, dated May 2,1983, NRR found the licensee's design ac-ceptable as documented in a letter dated July 25, 1984. The inspector determined that the hydrogen monitor installed during the 1983 outage was replaced during the 1985 refueling outage with a combined hydrogen / oxygen

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monitor, manufactured by Exo-Sensor, Inc. Based on a review of the modi-fication package (F1-84-3), and on observations during plant tours, the inspector verified that the recently installed hydrogen monitor meets all the requirements of NUREG-0737 for item II .F. The inspector deter-mined that no changes were made to the range or sample points of the CHMS, and that the accuracy was increased to 2% of full scale. The control room CHMS indicators ~ were removed. A computer alarm is still available, and the licensee has the ability to monitor hydrogen levels using the computer; in addition, a direct readout and a strip chart recording of the CHMS is available in the relay room directly below the control room. This item is close III.D. Integrity of Systems Outside Containment Likely to Contain Radioactive Material In reviewing past inspection findings, the inspector noted that the li-censee had committed to performing a helium leak test of the Standby Gas Treatment System (SGTS), (discussed in Inspection Report 50-333/80-21 and followed up in 50-333/81-07). A " snoop" test (soap bubble) was performed on the discharge portion of SGTS on February 26, 1982, and work was con-ducted to seal the leakage found. The inspector found the " snoop" test method to be adequate to meet the requirements of NUREG-0737. The li-censee has agreed to incorporate a periodic leak check of the SGTS into their leak reduction program. This item will be reviewed in a subsequent inspection (50-333/85-25-04).

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11 s 1 Review of Periodic and Special Reports Upon receipt, the inspector reviewed periodic and special reports. The review included the following: inclusion of information required by the NRC; test results and/or supporting information consistent with design predictions and performance specifications; planned corrective action for resolution of problems; and reportability and validity of report informa-tio The following periodic reports were reviewed:

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August 1985 Operating Status Report, dated September 6, 198 September 1985 Operating Status Report, dated October 7, 198 . Unresovled Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or devia-tions. Both the unresolved items identified during this inspection are discussed in paragraph . Exit Interview At periodic intervals during the inspection, meetings were held with senior facility management to discuss inspection scope and findings. On October 11, 1985, the inspectors met with licensee representatives (denoted in paragraph 1), and summarized the scope and findings of the inspection as they are described in this repor Based on their rey!ew of this report, the inspectors determined that this report does not contain information subject to 10 CFR 2.790 restrictions.

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