IR 05000317/1989004

Insp Repts 50-317/89-04 & 50-318/89-04 on 890221-0403. Violations Noted.Major Areas Inspected:Operational Events, Maint,Surveillance,Radiological Controls,Physical Security & Process for Temporary Changes to Plant Equipment

ML20246L887
Person / Time
Site:	Calvert Cliffs
Issue date:	05/05/1989
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20246L860	List: IR 05000317/1989004 ML20246L855 ML20246L863
References
50-317-89-04, 50-317-89-4, 50-318-89-04, 50-318-89-4, NUDOCS 8905180421
Download: ML20246L887 (31)

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U. S. NUCLEAR REGULATORY COMMISSION Region I 50-317 DPR-53 Docket Nos.: 50-318 License Nos.: DPR-69 50-337/89-04

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Report Nos.: 50-318/89-04 Licensee: Baltimore Gas and Electric Company

, Post Office Box 1475 l' Baltimore, Maryland 21203 L Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection at: Lusby, Maryland Inspection Conducted: February 21 - April 3,1989 l Inspectors: H. Eichenholz,. Senior Resident Inspector l V. Pritchett, Resident Inspector P. W 1 son, Reactor Engineer i Approved by: ! '/A 5/SM9 Lodell E. Trip R Chief Date p Reactor Projects Section No. 3A Summary: February 21 - April 3, 1989: Inspection Report Nos. 50-317/89-04 and 50-318/89-04 Areas Inspected: Facility activities, routine inspections, operational events, maintenance, surveillance, radiological controls, physical security, NRC noti-fications, process for temporary changes to plant equipment. Licensee Event Reports, reports to the NRC, and licensee action on previous inspection findings.

l l Results: Four violations were identified in the following areas: failure to implement and establish procedures (see Sections 3.B, 3.H 3.I, and 4); failure to satisfy snubber surveillance requirements (see Section 5); failure to properly implement emergency plan and the fire protection program (see Sectio .A); and failure by POSRC to review operational events for potential safety hazards (see Sections 3.G, 3.J and 4).

l Performance in the area .of safety assessment has been inconsisten It I included weaknesses as demonstrated in the failure to identify the root causes of the leak in the steam generator blowdown line and a failure to demonstrate appropriate conservatism in the approach to resolution of this issue from a l

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safety standpoin It also included strengths exhibited during resolution of the events described in Sections 3.C, 3.E, and PDR ADOCK 05000317 O PNV g 9-

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..< .s TABLE OF CONTENTS Page Summary of. Facility and NRC Activities . . . . . . . . . . . . 1 J Operational Safety' Verification (IP_71707) . . . . . . . . . . 2 . Daily Inspection. . . . . . . . . . . . . . . . s .... 2.

E System Alignment Inspection . . . . . . . . . . . . . . . 2 Biweekly and Other Inspections. . . . . . . . . . . . . . 3

[r . Operational Events (IP 93702, 62703) . . . . . . . . . . . . . 3 Fire in Unit 2 Auxiliary Feedwater Pump Trip Circuitry. . 3 Partial ~ Loss of. Condenser Vacuum, Unit 2. . . . . . . . . 5 Unit 2 Shutdown Due to'#22 Steam Generator Main Feedwater Regulating Valve Positioner Failure . . . . . 7 Loss of Operability of Nos. 11 and-12 Salt Water Air Compressors Due to Failure of Instrument Air System Check Valve 1-IA-650 .... ............ 8 Nuclear Fuel - Potential' Loss of Shutdown Margin. .... 10 Identification of Damaged Seismic Restraint on #11 and

1. 12 Low Pressure Safety Injection Common Suction Header-and Subsequent Water Hammer Evert. ....... 11- Unit-2 Shutdown Due to.#22' Steam Generator Blowdown Line Leak . . . . . . . . . . . . . . . . . . . . . . . 12 Inadvertent Engineered Safety Feature Actuation with Injection'- Unit 1. . . . . . . . . . . . . . . . . . . 14 Inadvertent Partial Engineered Safety Feature Actuation Without Injection - Unit 1. . . . . . . . .. . . . . . . 15 Unit 1 Shutdown Due to High Sulfate Concentrations in the Reactor Coolant System. .............. 16 p Maintenance Observations (IP 62703). . . . . . . . . . . . . . 18 Surveillance Observations (IP 61726, 62703). . . . . . . . . . 21 Radiological Controls (IP 71707) .. . . . . . . . . . . . . . . 2L Observation of Physical Security (IP 71707). . . . . . . . . . 22 Process for Temporary Changes to Plant Equipment (IP 37700). . 23 Events Requiring NRC Notification (IP 93702). . . ..... 25 T-1

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' Table of Contents (Continued)

Fage 10. Review o' ', ensee Event Reports (IP 90712, 92700) . . . . . . 26 11. Review of Periodic and Special Reports (IP 90713). . . . . . . 27 1 Licensee Actions on Previous Inspection Findings (IP 93702,

92701). . . . . . . . . . . . . . . . . . . . . ...... 27 1 Unresolved Items . . . . . . . . . . . . . . . . . . . . . . 28 14. Management Interviews (IP 30703) . . . . . . . . . . . . . . . 28 l

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l DETAILS Within this report period, interviews and discussions were conducted with various licensee personnel, including reactor operators, maintenance and surveillance technicians and the licensee's management staff. Night shift inspections were conducted on March 1, 2, 7, and 31,1989 and weekend inspections were performed on March 4,12,19, and April 1,1989, Summary of Facility Activities Unit 1 The unit began the period at power. The unit went to hot standby on February 26 and 27,1989, to repair a leaking third stage extraction line tap-off. The unit entered a mini-outage on March 2,1989, to replace #11 Reactor Coolant Pump seal (with a new Bingham seal) and to correct control room deficiencies. On March 26, 1989, the plant heated up and paralleled to the grid on March 29, 198 Later on the same day the unit was shut down due to high sulf ates (see Section 3.j). The unit ended the period shut down due to a I.igh concentration of sulfates in the reactor coolant system (RCS).

Unit 2 The unit began the period at powe On February 23, 1989, power was reduced to 92% due to fish influx which required stopping #22 Circulating Water Pump on high travelling differential pressur The unit was returned to power on the same day. A fire in the control room handswitch for the #22 auxiliary feedwater pump's throttle / trip valve occurred on March 1, 1989 (see Section 3.a).

On March 7, 1989, power was reduced to recover from a partial loss of condenser vacuum (see Section 3 b). That same day, the unit was shut down to repair #22 Feedwater Regulating Valve (see section 3.c). The unit returned to power on March 9, 1989. On March 17, 1989, the unit was shut down due to an increasing leak on #22 steam generator blowdown piping (see Section 3.g). The unit entered 'the refueling outage on March 24, 1989, and ended the period shut down for a planned 65-day refueling outag General On February 22, 1989, U.S. Representative Thomas McMillen visited the site to tour the facility and meet with the resident inspector An NRC Special Team Inspection was conducted at the site during the weeks of February 27, March 6, and March 29, 198 During the week of February 27, 1989, Region I personnel inspected in the area of Environmental Qualificatio _ _ _ _ _ _ _ _ _ - _ _ _ - - _ - _ _ - - _ _ _ _ _ _ _ . _ _

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On March 3, 1989, the licensee and NRC held a public meeting at the facility to discuss the results of the Systematic Assessment of Licensee Performanc During the week of March 27, 1989, the Institute of Nuclear Power Opera-tions (INPO) conducted a Special Assist visit in the areas of Significant Operating Event Reports and Human Performance Evaluation Syste . Review of Plant Operation - Routine Inspections (71707) Daily Inspection During routine facility tours, the following were checked: manning, access control, adherence to procedures and LCO's, instrumentation, recorder traces, protective systems, control rod positions, contain-ment temperature and pressure, control room annunciators, radiation monitors, effluent monitoring, emergency power source operability, control room logs, shift supervisor logs, and operating order No unacceptable conditions were note System Alignment Inspection Operating confirmation was made of selected piping system train Accessible valve positions and status were examined. Visual inspec-tion of major components was performed. Operability of instruments essential to system performance was assessed. The following systems were checked during plant tours and control room panel status observations:

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Unit 1 Chemical Volume Control System

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Unit 1 High Pressure Safety Injection

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Unit 1 Low Pressure Safety Injection

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Unit 2 Service Water System

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Unit 2 No. 12 Emergency Diesel Generator Air Start System No unacceptable conditions were noted.

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- Biweekly and Other Inspections During plant' tours, the inspector observed shift turnovers; boric acid tank samples and tank levelsL were compared to the Technical .

Specifications; and the use of radiation work permits and Health Physics procedures were reviewed. Plant housekeeping and cleanliness were evaluate No unacceptable conditions were note . Operational Events (93702) Fire in a Unit 2 Auxiliary Feedwater Pump Trip Circuitry On- March 1,1989, with Unit 2 operating at 100% of rated power, a fire under the bench board section of control room panel- 2004 occurred at 4:47 p.m. The fire involved the burning of the hand-switch (2-MS-3988-HS) for the #22 steam driven auxiliary feedwater (AFW) pump's throttle / trip valve (2-MS-3988). At approximately the same time a turbine building operator reported that the solenoid (2-MS-3988-SV) for the throttle / trip valve was also smoking and appeared to have overheated. The duration of the fire in the hand-switch' lasted between one and two minutes. A portable halon fire extinguisher was used twice by a control room operator to extinguish the fire. At the time of this eve the No. 22 AFW pr .np was out of service for the repair of a faulty trip reset mechanism and the hand-switch was being used to verify proper movement of the valve as part of post maintenance testing. NRC review of the licensee's mainten-ante activities on the subject valve ~ and maintenance actions to

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recover from the event are contained in Section 4 of this repor As a result of the fire, minor damage to wiring adjacent to the hand-switch was noted. This wiring is associated with the steam inlet pressure indicators (2-PI-3987 and 2-PI-3989) for the #21 and #22 AFW pumps. Operability testing of electrical components located on the 2C04 panel and temporary repairs to the affected wiring were com-pleted at 9:25 p.m. and H:45 p.m. , respectively. An informational ENS call was made at 5:34 Because this event was viewed by the licensee as being significant, the Manager-Calvert Cliffs Nuclear Power Plant Department (CCNPPD)

established a Significant Incident Findir:g Team (SIFT) on '

March 2, 1989, to determine the root cause(s), initiate corrective action, and make recommendations to prevent recurrence. The results of the SIFT's investigation, conclusions, and recommendations were

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submitted and reviewed at Plant Operations Safety Review Committee (POSRC) Meeting No. 89-52 on March 24, 198 This resulted in the issuance of Calvert Cliffs Event Report 89-01 on March 29, 1989. The i inspector noted that this report reflected positively on the detailed and thorough investigation and resulted in the development of appro-priate recommendations that were generally introspective and self-critical of the licensee's performanc The licensee's investigation revealed that during reinstallation of the actuator, insufficient clearance was provided in the overspeed trip linkag This allowed the remote trip function of the valve to actuate by energization of the trip solenoid but, prevented actuation of a shunt mechanism that inserts a larger resistance coil in the circuit. By failing to actuate the shunt device, full closing cur-rent of about 30 amperes remained on the circuit instead of the normal 0.25 ampere holding current. Under this condition, momentary use of the control room handswitch resulted in welding closed the switch contacts. Since the handswitch is only rated for 2.5 ampere service, and the 10 ampere fuse in the circuit is sized to protect the circuit wiring, the overload condition resulted in the fire in the handswitc Once the fuse blew the circuit over load was inter-rupted. The proper actuation of the shunt device is the function in the circuit intended to prevent an over load condition during the remote closing of the valv The inspector identified no design inadequacies during the review of the control circuit for the AFW pumps throttle trip valve. However, the licensee has issued Field Change Request (FCR) 89-0035 to re-evaluate the existing design and improve the design of the remote trip functio .

The inspector had the following additional comments pertaining to the licensee's performance in response to this event: I

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Directly following the event, the operations department responded well by demonstrating an appropriate level of concern for the potentially negative impact that the control room panel fire could have had on adjacent control circuits. However, the testing program used an extensively altered procedure STP-0-9-2, Auxiliary Feedwater Actuation System, Monthly Logic Test. NRC concerns pertaining to the licensee's inappropriate control of procedure changes will be documented in the report of the Special Team Inspection (50-317/318: 89-200). All control cir-cuits and associated equipment were subsequently verified to be operable.

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The immediate response of the control room personnel included a the use of a portable fire extinguisher twice 'to contain Land extinguish the fire; telephone paging three times the fire and safety technician, who functions as the fire brigade leader; and calling for an electrician to come .to the . control room. Because the fire-was out quickly, the emergency alarm 'was not sounded and the fire brigade was not assembled. It' appeared that at the-time this decision was made the control room personnel wer neither. aware of the conditions that caused the fire, nor con-sidered the possibility that what appeared to be a controlled situation could degrad Calvert Cliffs Instruction (CCI) 133 I, Calvert Cliffs Fire Protection Plan, requires in Section VII that the control room operator sound the emergency alarm and announce the location of the. fire over the public address system. Additionally, Emerg-ency Response Plant Implementing Procedure (ERPIP) 3.0,. Revision 13, Immediate Actions, requires the control room to notify on site personnel of a reported fire by sounding the emergenc public address alarm, announcing the location of the fire and j notifying the Fire Brigade Leader by radio . pager. Technical Specification (TS) 6.8.1.e and f, respectively specify, in part, that written procedures shall be implemented for Emergency Plan and Fire Protection Programs. The failure of control room per-sonnel to implement the requirements of the above enumerated procedures during the fire in the control room panel is a violation-(50-318/89-04-01). Partial Loss of Condenser Vacuum, Unit 2 On March 7,1989, at 1:28 a.m., the unit was operating at 100% powe The Unit 2 Turbine Building Operator (TBO) was performing a condenser air in-leakage check per Operating Instruction (01)-13, Part IV, Condenser Air In-Leakage Chec The TB0 skipped a step in the pro-cedure which resulted in a valve lineup which provided a path from atmosphere to the condenser. Vacuum rapidly decreased causing con-trol room low vacuum alarms. Control room operators responded to the alarm condition by reducing power and the TB0 corrected the valve lineup and caught the decreasing vacuum at 22.5 inches hig The automatic turbine trip occurs at 20 +/- 2 inches hig The condenser air removal units use an air ejector in combination with a mechanical vacuum pump to maintain condenser vacuu The ejector utilizes air from atmosphere via a three way valv When performing the air in-leakage test, the three-way valve is positioned so that outside air is isolated. Thus, by isolating the discharge

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header isolation valve to the plant vent, the only air being forced through a flowmeter used to measure in-leakage by the vacuum pump would be in-leakage. The flowmeter line is capable of handling relatively small air flow rate When the three-way valve was not positioned in accordance with the procedure, the capacity of the flowmeter tubing was exceeded and air backed into the condenser thereby reducing vacuu The control room operator began inserting control rods to reduce power in accordance with Abnormal Operating Procedure (AOP)-7G, Partial Loss of Condenser Vacuum. The TB0 observed the flowmeter indication was pegged high and opened tne plant vent header isolation valve in accordance with 01-13. Vacuum decrease stopped. Other plant personnel responding to page announcements found the three-way valve mispositioned and repositioned the valv Vacuum began to increase slowly. Vacuum returned to normal approximately ten minutes after event began. Power was decreased to 96% power and returned to 100% shortly thereafte A0P-7G requires a turbine trip when condenser vacuum is less than 24.5 inches high for more than about one minute. The licensee states the operator did not trip the unit because the improper lineup had been identified and corrected about the same time the control room operator identified the trip criteria. The licensee contacted the turbine vendor to determine the effect of operating the turbine in the low vacuum environment. The turbine vendor indicated no damage would occu Corrective actions that were under consideration or implemented at the close of the inspection period included (1) review of the factors leading to the procedure non-adherence with operations personnel (completed); (2) label the position on the three-way valve; (3) con-sider reducing the frequency of the condenser air in-leakage check from daily to weekly; (4) install a sign on header isolation valv2 to plant vent warning that valve position is trip sensitive; (5) relo-cate flowmeter indication so it is visible from header isolation valve positioner; and (6) correct in plant communication problem Timely operator action avoided potential safety system challeng TS 6.8.1.a and Reg. Guide 1.33, Appendix A requires that the proced-ures for power operation be implemented. Tne failure to follow 01-13 is considered an example of a violation of TS 6.8.1.a requirements (317/89-04-01; 318/88-04-02).

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7 Unit 2 Shutdown Due to No. 22 Steam Generator Main Feedwater Regulating Valve Positioner Failure On March 7,1989, at 8:00 a.m. , with Unit 2 operating at 100's power, control room personnel contacted the secondary system engineering group and informed them of increases in the perturbations in the unit's feed system. The unit had been experiencing some minor feed system perturbation Investigation revealed that the perturbations were related to the Feedwater Regulating Valves (FRV) controls. Addi-tionally, it was determined that further investigation would require a shutdown. Shortly thereafter, steam generator (SG) level oscilla-tions increased to approximately +/- 5 inch deviation from the 0 inch reference value. Control room personnel dispatched plant personnel to investigate the oscillations and while the investigation was in progress at approximately 11:40 a.m., #22 SG level began to decrease at an unexpected rate. At 11:45 a.m., AOP 3G was entered and control room personnel recovered level using manual feedwater system contro The #22 SG level had decreased to - 31 inches prior to returning to the normal value of 0 inches. During the event, all reactor protec-tion system (RPS) low SG 1evel pre-trip alarms were received; no RPS or engineering safety features actuation system (ESFAS) setpoints were reache Plant watch personnel discovered that air was blowing from #22 SG FRV positione It was decided to place #22 FRV in manual control for troubleshooting and/or repairs, in accordance with 0) 12A, Feedwater System. With the #22 FRV in manual control, the plant entered TS 3.0.3, at 12:20 p.m., based on not meeting TS Limiting Condition for Operation (LCO) 3.3.2.1, ESFAS response time for #22 SG FR Troubleshooting of #22 SG FRV positioner indicated that a gasket failure was the cause of the air leakage. Repairs were completed and the plant exited the TS Action Statement 3.0.3 at 2:20 Shortly thereafter, the POSRC met and concluded that post maintenance testing of #22 SG FRV was required to verify TS Surveillance Require-ment 4.3.2.1.3, Engineering Safety Features Response Time, Table 3.3-5.8(a), feedwater flow reduction to 5*6 on a reactor trip. A unit shuto:wn was initiated at 4:00 p.m. and TS 3.0.3 was reentered for not meeting TS LC0 3.3. At 4:55 p.m., utilizing the ERPIP, an Unusual Event was declared and ENS notification was mad At 6:57 p.m. , Mode 2 was entered and Mode 3 was entered at 7:10 Following the reactor shutdown, Surveillance Test Procedure (STP)

M-521-2, ESFAS Time Response Test, was performed satisfactorily on

1. 22 SG FRV to obtain as found data. Following adjustment to the air pressure reading, STP M-521-2 was again performed satisfactorily and at 11:30 p.m., the unit exited TS 3.0.3 and the Unusual Even _ _ - _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ - _ . _ _

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i The licensee determined that the cause of failure of #22 FRV I

positioner was failure to perform adequate preventive maintenanc The air leak was caused by a gasket which was in a brittle and degraded condition. Present work practices do not provide for review, overhaul and replacing of gaskets on secondary system com-ponents. A similar event which resulted in a unit trip is discussed in Inspection Report 50-317/88-19; 50-318/88-1 The licensee is considering the following recommendations in order to avoid future recurrence: (1) Establish Reliability Centered Main-tenance (RCM) for the Feedwater Regulating Valve actuators and positioners to determine the best preventive maintenance cours (2) Establish a list of and perform a review of all vital secondary components in a harsh environment to determine if adequate preventive maintenance is performe Throughout this event, the inspectors observed and noted that the licensee's decisions and performance exhibited the proper safety perspective and conservatis Loss of Operability of #11 and #12 Salt Water Air Compressors Due to Failure of Instrument Air System Check Valve 1-IA-650 On March 14, 1989, at 9:00 p.m., Unit I was in Mode 5. An instrument air boundary check valve (IA-650) failed a back leakage test. Subse-quently, the check valve was replaced and two manual isolation valves were installed to allow for header isolation in Eddition to facil-itating future replacement of any leaking check valve. The new check valve was tested several times and faile The licensee's design engineering group determined that loss of the valve due to its loca-tion would jeopardize both salt water air compressors (SWAC) and, therefore, both trains of the salt water system. This determination was made at 1:30 p.m. on March 24, 1989, and an ENS notification was made at 2:50 The testing, which resulted in the identification of the failed valve on March 14, 1989, was triggered by a partial loss of instrument air (IA) which occurred in Unit 1 on December 20, 1988 (see Ir.spection Report 317/88-32). The significance of the December partial loss of IA was that once the source of that bleed down of IA was located and isolated, the SWACs should have had the capacity to supply the feed-water regulating valve (FRV) and prevented the feedwater transient which occurred. As mentioned above, on March 17, 1989, the old check valve (IA-650) was replaced with a new check valve and two manual i

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isolation valves. Further test showed some improvement in the leak rate, however, the licensee decided to isolate IA-650 and has placed an- order for a soft seat. type check valve. Essential load to the

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containment is supplied via an alternate- pat On March 25, 1989, the licensee tested the salt water 'IA system in . the new configura-tion, including check valve IA-730 which became the new boundary valve between safety related and non-safety related, and the results

+ were satisfactor The SWACs were added to .the IA system in July 1974. Originally, it was determined that during every mode of operation and event except Loss of Coolant Accident (LOCA) before recirculation', the salt water .

syster, would have to be throttle The throttling requirements resulted from the potential run out of the salt water pumps. There-fore, the discharge valves on the component cooling and service water heat exchangers were modified to allow the valves to be supplied alternately from the SWACs during a LOC Upon receipt of safety injection actuation signal (SIAS), the SWACs start automatically to. provide backup air to the aforementioned. heat exchanger discharge control valves. Normally IA is secured after a SIAS and is restored once service water is restored to the turbine building and SIAS is rese IA system essential' and non-essential loads are separated by boundary check valves except for containment loads which are separated by an air pressure switch actuated air-controlled isolation valve, Once the SIAS signal is received, the SWACs supply air only to essential loads upon IA header pressure decreasing to the point where the boundary check valves seat. Hence, the loss of one of the boundary check valves could result in total loss of IA due to the capacity ?f the SWAC The licensee has identified that with the worst e u scenario of a LOCA with concurrent loss of off site power, the Nt water air system would be rendered inoperable when considering the excessive back leakage through boundary check valve IA-650. This would result from not Nving a c.on stant ;ir source in order to throttle the salt water heat exchangers discharge control valve The lack of air to throttle the discharge control valves would result in run out of the salt water pumps and eventual loss of the component cooling water systems and the service water system. The postulated event was considered reportabl The following corrective actions have been implemented or are under consideration: (1) Install manual isolation valves on either side of IA-650 to allow for its isolatio (2) An additional pathway for IA compressors supplying air to containment essential loads was established through IA piping to the auxiliary feedwater components normally isolate The configuration of the salt water air system

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l was verified to be safe'by safety analysis and POSRC. (3) A new soft seat check valve is being reviewed to replace the existing on (4) Unit 1 boundary check valves that were not tested will be tested t

in accordance with the overall effort to respond to .NRC Generic Letter 88-14 " Instrument Air Supply Problem Affecting Safety-Related Equipment." (5) The Unit 2 IA system will 'be tested to identify any similar problem No unacceptable conditions pertaining to the licensee's response to this event were noted, e. Nuclear Fuel - Potential Loss of Shutdown Margin In May 1988, the licensee received NRC Information Notice 88-2 This notice alerted licensees to undesirable procedural practices that could lead to inadvertent criticality events. Based upon their initial review, the licensee requested information from their fuel supplier, Combustion Engineering in November 1988. At that time, the licensee was developing concerns that the increasing enrichment of fuel over the last several fuel cycles, with some of the fresh fuel assemblies being highly reactive under refueling conditions, in con-junction with their refueling procedures allowing replacement of fuel assemblies in intermittent positions during core alterations, could challenge the required five percent shutdown margin. In the extreme, the licensee was concerned that such conditions could allow an inadvertent criticality to occu On March 10 and 15 respectively, the licensee provided telephone notification and written follow up for their determination that the potential loss of shutdown margin meets the criteria of a defect on a basic component as defined in 10 CFR 21. Combustion Engineering-issued Information Bulletin No. 89-01 on March 14, 1989, describing the potential concerns iaentified by the licensee. The licensee has informed the inspector that procedure FH-6, Core Refueling Procedure, will be revise When questioned by the inspector as to why this event was not report-able under 10 CFR 50.72 and 50.73, the licensee's representatives indicated that it was their judgment that since (1) the probability of forming potentially critical configurations or reduced shutdown margin configurations as a result of interim fuel moves was extremely small and (2) that interim fuel moves had not been identified to have been used during recent Unit 2 refueling cycles, the condition was not reportabl The manner in which the licensee performed operational assessment feedback evaluation of NRC Information Notice 88-21 demonstrated good performance in resolving this technical issue from a safety stand-poin The inspector had no further questions of the licensee on this ite _ _ _ _ - - _ _ - _ _ _ _ - _ _ _ . - _ _ _ . ____. _ - . A

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33 Identification of Damaged Seismic Restraint on #11 and #12 Low Pressure Safety Injection Common Suction Header and Subsequent Water Hammer On March 17, 1989, at approximately 12:30 p.m. with Unit I shut down in Mode 5, a licensee system engineer observed that a vertical sup-port on the Low Pressure Safety' Injection (LPSI) System suction pip--

ing was bent. The system engineer' notified design engineering, qual-ity control and operations. Further, the licensee contacted Bechtel to obtain their assistance in determining the amount of force required to distort the suppor Bechtel determined that approxi-mately 5,300 pounds of force would have been required. The licen-see's design . engineering group designed a new replacement . pipe restrain Bechtel reviewed and confirmed that with the new design, the stresses on the LPSI suction piping would not be exceeded. The licensee determined the most likely cause of the vent was #11 LPSI pump discharge check valve slamming shut when the pump was tripped generating the force to bend the restrain POSRC approved the new design restraint on March 18, 1989. The installed restraints were removed ~ on March 19, 1989. During the removal process, there was an inadvertent SIAS actuation. LPSI sys-tem suction piping was observed to move approximately 1/16th of an inch. Operators secured the SIAS actuation and when #11 LPSI pump was stopped, the pump's discharge check valve slammed-shut. The LPSI suction piping was observed by workers in the room to move a total of-approximately 1 inch in the east-west. direction. The licensee 'evalu-ated the evidence confirming that the slamming check valve could have

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caused the damage. They concluded that the damage to the restraint-occurred when the check valve slammed shut following #11 LPSI pump trip causing the resulting force in the direction toward the pump and suction piping, a

The licensee installed the new design restraint on March 19, 198 '

The following corrective actions were performed by the licensee prior to declaring the LSPI system operable: )

(1) The inservice inspection (ISI) group performed a walkdown of Unit I high pressure injection system, containment spray system and component cooling water system to inspect for damage. No significant damages were foun (2) The discharge check valves on #11 and #12 LPSI pumps were tested for back leakage and found acceptable.

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(3) The #11 LPSI pump was checked for excessive vibration caused by possible misalignment due to the event. No problems were foun I

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(4) The piping supports were reinspected after the SIAS even No problems were foun (5) The ISI group inspected the LPSI discharge and suction piping up to the first hanger and found no problem (6) The ISI group performed NDE testing on five suction piping welds and on the pump suction nozzle weld and found no problem The POSRC declared the system operable following completion of the aforementioned ite The licensee's 0.- alta Safety Review Committee and interfacing groups displayed proper safety perspective throughout this event including the solutions and conclusions. The NRC considers this proper func-tioning of the committee and proper utilization of available tech-nical resource g. Unit 2 Shutdown Due to No. 22 Steam Generator Blowdown Line Leak On March 7,1989, Unit 2 was operating at 100% power. The unit was shut down at approximately 7:00 p.m. to repair #22 FRV (see Section 3.c).

During the shutdown, a routine containment walkdown identified a leak on the #22 SG bottom blowdown line near the 10 foot elevation. The leak was identified as geometrically round and characterized as a pin hole located on the vertical run of pipe. Concurrent with the dis-covery of the blowdown line leak, a heavy rust area was discovered in Unit 2 salt water system in the service water room. Later in the ;

evening of March 8,1989, it was concluded that there was not a :

through wall failure in the salt water system since the pipe wall i satisfied thickness minimum wall requirement I Based on recommendations from the system engineer, material engineer-ing group and design engineering group, the licensee elected to take j the unit to power on March 9,1989. The licensee's decision to con- l tinue to operate with an unisolated leak in the blowdown line was based on the following (1) examination showed that the blowdown pipe )

leak was a localized pin hole which was not likely to propagate with-

in the following two weeks (two weeks was the time to the licensee's l refueling outage); (2) the leak was characterized to have been next to and associated with the weld start /stop point where excess rein-forcement weld material was present; (3) the leak rate was small

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(estimated 2 gallons / hour); (4) the leak would be monitored using the

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containment sump which was drained after each accumulation of approx-imately 44 gr.llons; (5) the unit would enter the refueling outage in l two weeks, thereby allowing for the expeditious repair of the line; and (6) catastrophic failure, although considered unlikely, was bounded by Chapter 14 Feedwater Line Break Analysi In addition, the licensee based their position on ASME XI, IWA 5250 which they believed allowed sources of leakages to be evaluated by the licensee for corrective actio On March 9,1989, Unit 2 was at 30% power holding for chemistry. The licensee held a conference call with NRC Region I (NRC:RI) and NRC Office of Nuclear Reactor Regulation (NRC:NRR) which resulted in the following agreements: (1) The licensee would question their Author-ized Nuclear Inspector and determine whether he agreed with the licensee's interpretation of the ASME code. (2) The licensee would solicit a code interpretation to clarify vagueness of the code rela-tive to leaks on Class 2 piping. A subsequent conference call on March 10, 1989, among the aforementioned groups conveyed the addi-tional NRC position that a relief request from ASME Code Section XI was needed from the licensee. The licensee volunteered that should the sump drain interval reach once every eight hours, an entry into the containment would be made along with a re-evaluation. Further, if the sump drain interval reached once very 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the unit would be shut dow On March 15, the unit had been operating at or near 100% power since March 1 A conference call was held between the licensee, NRC:RI and NRC:NRR to discuss the increases in containment sump drain inter-val and to further discuss the licensee's course of actio The licensee again volunteered to shut down should containment sump interval reach every 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> During this conference call, the licensee indicated that the pin hole defect was, in fact, in the base metal in an active section of the blow down line. The NRC was pre-viously informed that the pin hole leak was in the weld material and that the relatively large pressure drop was being absorbed by the tortuous path provided by the fillet wel On March 16, 1989, the licensee made an entry into the containment and presented their find-ings to POSRC. Subsequently, another conference call between the licensee, NRC:RI and NRC:NRR was held to discuss the status of the leak. A decision was made by the NRC to deny the code relief request effective 12:00 p.m. on March 17. The inspector was notified at 2:00 a.m. on March 17 that the sump drain interval had reached less than once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and a shut down of the unit had commence The licensee requested code relief to hold in Mode 3 for testin The request was denied and the licensee entered Mode 5 at approxi-mately 1:30 a.m. on March 18, 198 _ _ _ - _ _ _ _ - _ .

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The inspectors observed the above events and reached the following conclusions:

(1) The Chairman of the POSRC failed to exercise his duty by not utilizing a significant technical resource consistent with the Technical Specifications 6.5.1.6.g which specified the respon-sibilities of the POSRC for " Review of facility operations to detect potential r,afety hazards".

(2) The licensee failed to recognize the potential for challenging safety systems and entered into power operations without fully recognizing a reduced safety margi (3) Significant emphasis was piaced on the weld defect aspects of the problem while the potential contribution made by cavitation /

erosion / corrosion was de-emphasized or ignore (4) Solutions were structured to provide justification for continued operation without the proper safety perspectiv The failure of the P0SRC to review the through wall leak on the #22 SG blow down line for detection of potential safety hazards prior tc, the return of Unit 2 to power on March 9, 1989, constitutes one example .af a violation of the TS requirement 6.5.1.6(g)

(317/89-04-Oc, 318/89-04-03).

h. Inadvertent Engineered Safety Feature Actuation with Injection-Unit 1 On March 19, 1989, at 2:30 p.m. , with Unit 1 in Mode 5, operating personnel caused an inadvertent SIAS signal, which is part of the

, engineered safety features of the plant, during the performance of

[ Surveillance Test Procedure (STP) 0-7-1, Engineered Safety Features Monthly Logic Test.

l The unit was in Mode 5, pressurizer pressure was 250 psia and reactor j coolant temperature was 130 degrees F. In order to allow plant operations with pressurizer pressures below 1740 psia, which is one of the SIAS setpoints, the SIAS si nal9 can be blocked when pressur-izer pressure is below 1785 psi However, should pressurizer pressure increase above 1785 psia, SIAS will automatically be unblocke '

Since the test was being conducted below 1740 psia, the SIAS block ;

function had to be removed to allow for system testing. Attachment '

I of the STP accomplishes both the removal and reinstating of the SIAS pressurizer pressure blocking functio That portion of the test that demonstrated the operability of the trip circuits in the

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• 15 unblocked conditions was completed satisfactorily. During the riro-cess of reinstating the SIAS pressurizer pressure blocking function, the reactor operator (RO) in the cable spreading room who was per-forming the test failed to request and verify from the control room operator the procedural requirements of STP 0-7-1,. Attachment 1, to reinstate the bloc As a result of the missed step, a SIAS was initiate The RO returned to the previous step by returning the actuation pots to a minimu The control room had initiated E0P 8 (Functional Recovery Procedure), Attachment 2 (SIAS Verification Checklist) to verify that all systems had respondec as expected and was so noted. The SIAS was blocked and all systems were returned to normal with the exception of-the three emergency diesel generators which continued to run- loaded at required, for one hotr. The SIAS actuation pots were returned to their recorded setpoint The licensee will be reporting this event in an LER. The RO's fail-ure to follow STP 0-7-1 constitutes a violation of TS 6.8.1.a which requires the implementation of- procedures for conduct of TS surveil-

, lances (317/89-04-01; 318/89-04-02).

I. Inadvertent Partial Engineered Safety Feature Actuation without Injection - Unit 1 On Ms . ch 20, ~ 1989, at 1:20 p.m. with Unit 1 in Mode 5, operations personnel were restoring ESFAS Logic Cabinet "B" to service as per procedure OI 34, Section IX, Returning Actuation Logic Cabinets to Operation. There were two operations personnel involved, one R0 who was performing the steps in the procedure and a Senior Reactor Oper-ator (SRO) who was observing. The R0 had completed the performance of step 25 of the procedure and requested that the SR0 call the con-trol room to confirm the Steam Generator Isolation Block in alarm condition. The RO returned to the procedure and performad steps 28 and 29. After completing step 29, the RO became aware he had skipped steps 26 and 27 of the procedure. The R0 and SRO called the control room and conferred as to the best solution. It was collectively decided to back out of the procedure (i.e., undo steps 29 and 28).

The R0 then proceeded to do steps 26 through 29. The control room

!- informed them of a partial actuation of the ESFAS "B" logic. The #12 boric acid pump started, #12 component cooling pump started and high pressure safety injection (HPSI) motor operated valves (MOVs)

1-SI-616, 626, 636, 646 opened. The pumps were stopped and the HPSI MOVs were shut after consulting the safety injection actuation check-list. ESFAS Logic Cabinet "B" was restored to service per 0I-34. An ENS notification was made on March 20, 1989, at 2:20 p.m. The fail-ure of operating personnel to follow procedure 01-34 which resulted in a partial actuation of ESFAS is an another example of violation

[ (317/89-04-01; 318/89-04-02).

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On March 8,1989, the licensee issued General Supervisor of Nuclear Operations (GSN0) Standing Instruction 89-2, Supervision of Operation Activities, which indicated their elevated concerns with errors dur-ing major evolutions of the plant. The GSN0 Standing Instruction required a Senior Licensed Operator (SRO) to directly supervise the performance of certain evolutions including ESFAS startup, shut down, and operations testin On March 12, 1989, the GSN0 Standing Instructions were further clarificd to require the SR0; (1) to per-form no hands on operation; (2) must have a copy of the procedure being used by the operator he is supervising; (3) must acknowledge the completion of each step of the procedure and give his OK before the operator is allowed to perform subsequent steps; and (4) review discrete blocks of the procedare prior to each major ste The aforementioned enhancements to operations that were established by the licensee to help ensure proper attention to detail and procedural compliance by operations department personnel appears to have been ineffective to preclude the full and partial ESFs that occurred on March 19 and 20,1989, respectivel The licensee's inability to ensure procedural adherence is a continuing weakness that is of significant concern to the NR j . Unit 1 Shutdown Due to High Sulfate Concentrations in the Reactor Coolant System At 12:25 a.m. on March 29, 1989, the Unit I generator was paralleled to the grid following a maintenance outage that started on March 2, 1989. Plant heat up had started on March 26, 1989. Because of concerns expressed by the chemistry department that a potential release of chemical volume control system (CVCS) ion exchange (IX)

resins into the reactor coolant system (RCS) might have occurred, further increase in power level above 60's of rated power was stopped at 12:50 p.m. until the issue could be resolved. At 7:00 p.m., the Manager-CCNPPD instructed the plant operators to commence a shut.down of the unit to Mode 5. The inspector was informed by the Manager-CCNPPD of their actions, which resulted from the high sulfate concen-trations found in the RCS, Based upon recent RCS chemistry sample analysis and reduced radiation field measurements outside the #12 CVCS IX unit, the General Super-visor-Chemistry (GSC) believed that a significant intrusion of ion exchange resin into the RCS had occurred. The most significant con-cern to the licensee was that a sulfate species, thiosulfate, had been identified on March 29, 1989, along with the current sulfate (SO4) levels of approximately 200 ppb. The chemistry department uses j ion chromatography as the method to measure sulfate, which produced I

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an unknown or " ghost" pea Because they were concerned about the possibility of reduced sulfate compounds, sodium thiosulfate was added to the sample, which produced a similar ghost peak and led to the tentative identification of thiosulfat A review of licensee chemistry analysis reports indicated that on March 17, 1989, the sul-

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I fate level in the RCS was 97.2 ppb. Between March 20 and 24,1989, i the levels ranged between 1866 and 1272 pp At the Plant Operations and Safety Review Committee (POSRC) meeting  !

(No. 89-52) held on March 24, 1989, the GSC reported that a high sul-fate condition (1.9 ppm) existed in the Unit I shutdown cooling sys-te The GSC related that the TMI-1 experience with high sulfur in the RCS resulted in significant steam generator tube degradatio The POSRC was told by the GSC that a possible source of the sulfate contamination might be charging pump packing. The GSC also indicated that the existing primary to secondary leak on Unit 1 might be the result of sulfur attack in the primary side of the steam generator tubes instead of the normal secondary side tube degradation. At 6:00 p.m. on March 29, 1989, the current status of the sulfate levels in the Unit 1 RCS was discussed at POSRC meeting No. 89-57. Because thiosulfate was identified, and known to be an identified aggressive corrosion species on steam generator alloy 600 tubes, and since the total amount of sulfur was unknown and there was high probability of it plating out in the system, the GSC recommended Unit 1 be shut down and a clean up of the RCL initiated. Consideration was given to the addition of hydrogen peroxide to oxidize all the sulfur species to sulfate. The GSC had held discussions with EPRI, Combustion Engi-neering, and a consulting firm NWT, who considered the GSC's recom-mendations to shut down the plant and perform clean up activities to be pruden On March 30, 1989, a SIFT was formed by the licensee to investigate the cause of high sulfate concentrations in the Unit 1 RCS, determine corrective actions required to return RCS to normal chemistry condi-tions, and complete an effects analysis. At of the close of the inspection period, their investigation was in process and will continue to be reviewed by the NR The inspector reviewed the licensee's chemistry procedure CP-26',

Revision 1, Specifications and Surveillance of the RCS, which con- l tains normal and action level values for sulfate The last RCS chemistry results for sulfates prior to the heat up from Mode 5 on March 26, 1989 was on March 24, 198 This value was 1272 ppb. No chemistry analysis was performed on March 25 and 26,1989, however, a heat up from Mode 5 was initiate CP-204, Table IB, specifies

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that the normal value for sulfate in Modes 5 and 6 is less than 20 ppb. Table 1A of this procedure also uses this value for the Modes 1-4 normal range but, indicates that at a value of greater than 100 ppb an investigation into the cause and initiation of corrective action should occur. Although this procedure does not explicitly-prohibit a start up under the RCS chemistry conditions that existed on March 26, 1989, it appears that -less than fully effective manage-ment oversight was evident on the part of the chemistry department-in its application of this procedur Additionally, TS 6.5.1. requires the POSRC to review facility operations to detect potential safety hazard The licensee's plant start up on March 26, 1989, without a review by the POSRC of the existence and affects of high -

concentrations of sulfate in the RCS' to detect potential safety hazards is considered an additional ' example of a violation of TS 6.5.1.6.g requirement (317/89-04-02; 318/89-04-03).

4. Plant Maintenance (62703)

The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and main-tenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifications, fire protection, retest requirements, and- deportability per Technica Specification Unit 2 #22 Containment Spray Pump Bearing Failure On March 2,1989, during a ' routine review of the licensee's Non-Conform-ance Reports the inspectors discovered' that #22 containment spray pump (CSP) had experienced complete bearing failure on June 3,1987. Further inquiry indicated there had been little or no root cause' analysis, inade-quate documentation and no Plant Operating Safety Review Committee (POSRC)

revie The original NCR #7137 did not adequately document the investigation con-ducted by the system engineer at the time of closure which was in excess of one year after the even The event occurred on June 3,1987, with Unit 2 in Mode 5. Operations started #22 CSP at 2:00 a.m. to fill the safety injection tanks. At 2:55 a.m., operations secured #22 CSP due to a smoking bearing. The bear-ing was hot enough to blister the paint on the pum The original NCR mentioned a smoke alarm being receive No confirmation was found in either the operations logs or in fire protection record Maintenance Order (MO) #207-154-052A was issued to repair the pump. Inspection of the pump indicated significant discoloration of the housing shaft and bearings which is indicative of overheating. The shaft had more discoloration than

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the thrust bearing. The thrust bearing showed more damage than the other bearings and would not rotate. There was burnt oil residue throughout the bearing housing. T% M0 documented gross misalignment such that the coupling could not . removed without pump disassembly. The licensee believes that the gross misalignment was the cause of the bearing failur However, in the NCR closure, the licensee states the reason to be " low oil level". All parts resulting from this failure including the burnt oil sample have been misplaced or lost. Extensive search for the lost parts and oil sample have been fruitles A review of Nuclear Plant Reliability Data System (NPRDS) query report and in-house maintenance orders indicate this failure to be one-of-a-kin The licensee will be issuing an NCR to document the root cause analysis of #22 CSP failure. In addition, the following corrective actions will be or have been taken: (1) Continue monitoring oil reservoir level on at least a shift basis during tours of the ECCS rooms (in progress); (2) con-tinue a verification step in the surveillance test to document oil reser-voir filled prior to conducting the quarterly test (in progress); (3) con-tinue oil samples / change out on an annual basis (in progress); (4) add a step to sample / change out PM to verify bearing vent is unobstructed (May 15, 1989); (5) add steps to coupling grease PM to check / align pump and motor (May 15, 1989); (6) continue vibration program on the pumps (in progress); and (7) complete replacement of CSP bearing temperature ele-ment (TE) (when failure occurred TEs were the wrong type) (May 15,1989).

TS 6.5.1.6.g specifies that it is a responsibility of the POSRC to review facility operations to detect potential safety hazard Failure of the POSRC to review an event such as the complete failure of a bearing on a safety related component clearly indicates a failure to implement a funda-mental responsibility specified in TS 6.5.1.6 9 and therefore constitutes another example of a violation of this TS requirement (317/89-04-02; 318/89-04-03).

Maintenance on the #22 AFW Pump Throttle / Trip Valve An operator initiated Maintenance Request 38798 on January 23, 1989, that indicated the #22 AFW pump throttle / trip valve 2-MS-3988 would not reset without physical assistance. At 5:30 a.m. on March 1,1989, the #22 AFW pump was removed from service to allow repair of the faulty trip reset mechanism using Maintenance Order (MO) 209056262A. At 4:45 p.m., the o.me day, the control room operator placed the handswitch 2-MS-3988-HS '- . ,

shut position to test the remote trip of the valv As described in Section 3.a of this report, a fire occurred in the control room handswitch 2-MS-3988-H The fire was caused by the incorrect adjustment of the overspeed trip clearanc _ _ _ _ _ - _ - _ _ _ _ _ _ - . . _ _

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Factors that contributed to this maintenance activity resulting in a fire in the control room were:

(1) The M0 did not provide clear and specific instructions for performing post maintenance testing. Although the SE was aware of the need to test each trip function of the AFW pump following maintenance on the throttle / trip valve, he was not involved in the planning proces Additionally, the SE was not available to review the maintenance mechanic's resetting and manually tripping the valve several times with the trip level following valve actuator assembl Failure to test the overspeed trip function prior to testing the remote trip was a key contributor to this even (2) Adequate plant procedures that described removal and re-installation of the actuator were not available and the technical manual did not contain specific instructions for adjusting clearances. An informa-tion procedure had been developed by systems engineering about two years ago. This procedure clearly indicated the importance of adjusting the overspeed trip clearance. The current SE was not aware of the existence of this procedure. Failure to ensure that lessons learned from previous maintenance are incorporated in procedures and technical manuals was a contributing factor. Also, failure to estab-lish standards for system files contributed to the delay in incorpor-ating the alignment procedure into the technical manua TS 6.8.1.a and Appendix A of Reg. Guide 1.33, Revision 2, requires the licensee to establish procedures to ensure that maintenance that can af-fect the performance of safety-related equipment should be properly pre-planned and performed in accordance with appropriate procedures. The per-formance of maintenance on the #22 AFW pump's throttle / trip valve on March 1, 1989, without a procedure that included specific instructions for removal, reinstallation, adjustment, and testing of the actuator for this valve is an example of a violation of TS 6.8.1.a requirements (317/

89-04-01; 318/89-04-02).

As part of the licensee's corrective actions to repair t.he trip circuit of the #22 AFW pump's throttle / trip valve following the fire, MO 209-060-465A was issued to provide repairs as needed. Part of the repairs con-sisted of lifted lead activities to allow the addition of ir.sulation over wires that received minor damage because they were adjacent to the hand-switch. CNring inspector review of this maintenance activity, the inspec-tor developed concern pertaining to the adequacy of administrative con-trols and practices associated with lif ted lead and jumpers and CCI-117H, Temporary Modification Controls. The inspector's concerns pertaining to the damaged wiring repair controls were resolved by the licensee in a timely fashio However, the programmatic concerns developed by the inspector resulted in additional inspection in the area of temporary modification controls, which is documented in Section 8 of this repor _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - - _ - _ _ _ - _ _ _ _ - _ - _ _ _ _ _ - _ _ - _ - _ _ _ _ _ -_ _ _ _ _ _ - _ _ _ _ _ _ . _ _ _ - _ _ - _ ._-_-_________a

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21 Surveillance (61726)

The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results (if completed), removal and restoration of equipment, and deficiency review and resolutio The following tests were reviewed:

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STP 0-9-2, AFAS Monthly Logic Test observed on March 1,1989

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CP-204, Specification and Surveillance of Reactor Coolant System Snubber Testing Issue - Unit 2 On July 31,1986, the licensee submitted an amendment request to change the surveillance requirements for visual inspection and functional testing of snubbers to conform to their new refueling interval of 24 months versus 18 month In June 1987, the licensee was told following the initial review of the amendment request, that the change would not be approved because NRC needed to conduct a generic study on snubbers. The licensee was advised in early 1988 of the need to satisfy the surveillance requirement for their safety related snubbers. During the early 1988 spring outage, the licensee failed to perform the surveillance testing of the snubbers. On October 14, 1988, the licensee initiated a request for extension of the time interval to satisfy TS Surveillance Requirement 4.7.8. The interval extension requested was for 54 days. One time extension was approved by NRC:NRR on March 24, 198 The NRR Licensing Project Manager contacted NRC:RI and the inspectori on March 24, 1989, concerning a discrepancy in the test authorization data and the test completion date. The inspector requested a meeting with the licensee's system engineer (SE) and licensing engineer (LE).. The inspec-tor discovered that the test procedure and test results had been recreated and there was no way to confirm that the data was a true representation of the original dat The inspector notified the LE that unless verification of the original data could be made the unit did not satisfy Limiting Condition for Opera-tion 3 7.8.1 and was in the Action Statemen _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - -_ - _ - _ _ _ _ -

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The inspector was notified by the LE at approximately 3:00 p.m. that the SE and the LE could not reconstruct or verify the data on 6 cf the 47 snubbers involved. The inspector informed the LE that the NRC considers that a test without the required documentation to be a failure to perform the required Technical Specification Surveillance Testin The licensee notified the inspector that the POSRC had met and concurred with the inspector's interpretation and had entered the action statement at 5:45 p.m. on March 24, 1989. The licensee also notified the inspector-of their intentions to test all 17 snubbers required for the HPSI and shutdown cooling systems while in Modes 5 and Subsequently, the licen-see notified the inspector on March 25, 1989 that an error had been com-mitted in the number of snubbers required for Modes 5 and 6. The number of snubbers that required testing for the applicable mode increased from 17 to 86 and the licensee was planning to test 10% or 9 snubbers to sat-isfy the requirements. On March 26, 1989, the functional test required for Modes 5 and 6 was completed satisfactorily, hence, the surveillance requirements were satisfied and the unit exited the action statement within the allotted 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Current licensee plans call for the per-formance of required surveillance testing prior to entering . Mode 4 opera-tions at the completion of the refueling outag The inspector will review the results of this testing during a routine review of surveillance testin The failure to perform required surveillance testing, which includes the documentation for safety related snubbers as per Technical Specification Surveillance Requirement 4.7.8.1.c is a violation (318/89-04-04).

6. Radiological Controls (71707)

Radiological controls were observed on a routine basis during the report-ing period. Standard industr/ radiological work practices, conformance to radiological control procedures and 10 CFR Part 20 requirements were observe No unacceptable conditions were identifie . Observation of Physical Security (71707)

Checks were made to determine whether security conditions met regulatory requirements, the physical security plan, and approved procedures. Those checks included securi ty staffing, protected and vital area barriers, vehicle searches and personnel identification, access control, badging, l and compensatory measures when required.

No unacceptable conditions were noted.

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23 I I Process for Temporary Changes to Plant Equipment Federal regulations authorize licensees to make changes in the facility and procedures unless it involves a change to the Technical Specifications (TS) or an unreviewed safety question (10 CFR 50.59). The regulations also give guidance concerning what constitutes an unreviewed safety ques-tion and what reports and records are required as documentation. The licensee utilities the 50.59 process in making temporary changes to plant equipmen Permanent plant modifications also receive a 50.59 review but are handled using different administrative control The inspector reviewed the licensee's administrative instruction controlling temporary modifications, selected temporary modification packages and the Temporary Modification Log book. The inspector met with various members of the licensee's staff to discuss the temporary changes proces The licensee's administrative controls for their temporary modification process utilizes CCI 117H, Tempora ry Modification Contro A detail review of this procedure resulted in the inspector identifying significant weaknesses which are discussed belo CFR 50.59 requires the performance of a safety evaluation whenever the facility is modified as described in the Final Safety Analysis Report ( FSAR) . CCI 117H requires a 50.59 safety evaluation be considered only when the system / subsystem / component affected is safety related (as iden-tified by their Q-list) and/or contains radioactive gas, liquid or particulat TS 6.5.1.6.d requires the POSRC to review all proposed changes or modifi-cations to plant systems or equipment that affect nuclear safety. How-ever, CCI 117H allows the installation of temporary modification with interim approval from two SR0 licensed individuals one of whom must be the Shift Superviso POSRC review is then required within 14 days after implementation if the equipment affected is safety related and/or contains radioactive gas, liquid or particulat On June 28, 1988, a temporary modification (Serial No. 1-88-12) was implemented on Unit l's hydrogen analyzer containment dome sample line isolation valve. The temporary modification prevented sampling of the containment dome by the hydrogen analyzer. The hydrogen analyzer system is described in Calvert Cliffs FSAR (Section 9.6. and figure 9-11A) and is required to be operable by Calvert Cliffs TS 3.6. This temporary modification was implemented without the performance of a 50.59 evaluation. According to the licensee's sys-tem engineers, it is not possible to obtain a grab sample from that sample poin l j

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On ' May 23, 1988, temporary modifications. (Serial Nos. 1-88-97 and 2-88-66) were implemented 'on both Unit I and 2 which slightly increased the electrical load on the emergency diesel generators dur-ing a loss of off site. powe In order to provide adequate ventila-tion to both units' electric auxiliary feed pumps during a loss of-off site power, ..the licensee changed the power supply of the local ventilation unit #18 to motor control center (MCC) 101. During a loss of off site power, by ' procedure, the MCC is . switched onto the emergency busses. The MCCs and the ventilation units were not safety related, the'refore there was no POSRC review or 50.59 safety evalua-tion performed on this temporary modification even though the modifi-cation affected nuclear safet In addition to the- aforementioned concerns, the inspector , noted that numerous temporary modification activities were excluded from the CCI 117 instruction. These included: (1) lifted lead or jumper activities that are controlled by a maintenance order and are installed for less than one shift; (2) modifications activity that is performed under a' maintenance-order inside a safety tagged boundary and is recornmended by the implemen-ting individual during his work perio Although these exceptions appeared to be an attempt on the part of the licensee to allow for the need to perform troubleshooting activities without the use of the tem-porary modification controls, the inspector noted that the end result is a confusing procedure that incorporates potentially weak feature These exceptions were discussed with appropriate members of the licensee's staff, who acknowledged the comments and concerns and agreed to incor-porate appropriate guidance in the next revision to the instruction so that troubleshooting exceptions could only be used for that purpose, No temporary modifications were determined by the inspector to exist in either unit as a result of using, the exceptions allowed by the instructio The inspector reviewed the licensee's temporary modification logs for both Unit I and CCI 117H requires a log index be maintained as well as copies of all active temporary modification package When reviewed by the inspector, there were twenty seven temporary modifications listed in the log index as being active which not have their associated copies of the modification package in the log. When this was brought to the 11cen-see's attention, the licensee found all but two of the modification pack-ages and stated that those packages were close The inspector also noted that there was no apparent time limit on tem-porary modification One current temporary modification to Unit I was installed on August 27, 1982. There also appeared to be a large number of temporary modifications in existenc There were over seventy active temporary modifications in existence at the time of the inspectio Plant information documents such as system descriptions and prints may not fully and accurately represent the modified hardware and performance characteri stics.

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On March 10, 1989, a meeting was held with licensee staff members who are involved with the temporary modification process to discuss the above con-cern The licensee stated that CCI 117H was in the process of being revised and that they would correct the weaknesses observed. They also stated they would review all active temporary modifications to determine if 50.59 evaluations should be performed and/or POSRC cpproval is required. As an interim compensatory measure, the licensee issued a night order on Mcch 23, 1988, which required all proposed temporary modifica-L tions be reviewed by POSRC prior to installation.

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l The licensee has subsequently reviewed all active temporary modification packages that had not undergone a POSRC review (sixty-five packages). The licensee determined that six of the modifications required a 50.59 evalu-ation. The licensee has also determined that one of the six modifications may involve an unreviewed safety question; at the end of this inspection

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period, this issue was being reviewed by the Off Site Safety Review Committee.

During the conduct of the NRC's Special Team Inspection (317/89-200; 318/

89-200) performed between February 27 and March 31, 1989, numerous con-cerns pertaining to the development and implementation of the temporary modification controls process were identified by the team inspectors. As noted above, the licensee has been aggressive in responding to the NRC's l

concerns in this area, and has initiated appropriate engineering review and required POSRC reviews to currently be in conformance with applicable regulatory and TS requirements. Pending the issuance of Inspection Report 50-317/89-200; 318/89-200 and further NRC evaluation in this area, the acceptability of the licensee's implementation of temporary modifications in conformance with 10 CFR 50.59 and TS 6.5.1.6.d is considered an unre-i solved item (317/89-04-03; 318/89-04-05).

9. Events Requiring NRC Notification (93702)

The circumstances surrounding the following events, which required NRC notification via the dedicated ENS line, were reviewed. A summary of the inspector's review findings follows or is documented elsewhere as noted below:

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At 4:55 on March 7,1989, the NRC was notified in accordance with 10 CFR 50.72(a)(1)(i) that an Unusual Event was declared in anticipation of a Unit 2 shutdown to Mode 3 that was required by TS 3. The shutdown was required to demonstrate the response time for the #22 SG FRV. This event is discussed in section 3.C of this report.

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-- . At 2:15 a.m. - on March 18, 1989, the NRC was notified in accordance with 50.72(b)(1)(ii) that the #22 MSIV on Unit 2 failed one of the acceptance criteria during the performance of surveillance test pro-cedure STP 0-1-2H, MSIV Full Stroke . Test. The licensee made the -

event determination in accordance with CCI-118 L, Nuclear Operations Section . Initiated Reporting Requirements. The inspector questioned control room personnel as to why this event was reportable and learned that since they only had as little as one hour to determine if they had an event, they made calls in a very conservative manne Upon learning of the manner in which operations personnel made event

- deportability determinations, the inspector discussed with operations department management representatives that it is not clearly evident i

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that an event occurred, it is appropriate to conduct evaluation to analyze the ' event, determine deportability, and then initiate the

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notification within the appropriate time fram A review of the L details of why one of the acceptance criteria of the procedure was l not met for this event resulted in both the inspector and licensee

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concluding that this was not a reportable even At 3:10 on March 19, 1989, the NRC was notified in accordance with 10 CFR 50.72(b)(2)(ii) that an inadvertent engineered safety feature actuation occurred at 2:30 p.m., which resulted in the injec-tion of borated water into the Unit 1 RCS. The unit was in Mode 5 at the time. This event is further described in section 3.H of this report.

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At 2:20 p.m. on March 20, 1989, the NRC was notified in accordance l with 10 CFR 50.72(b)(2)(ii) that 'an inadvertent partial engineered safety feature actuation occurred at 1:20 p.m. with Unit I in Mode This event is documented.in section 3.'I of this repor At 3:45 a.m. on March 24, 1989, the NRC was notified in accordance with 10 CFR 50.72(b)(2)(ii)(D) that the failure of a Unit 1 instru-ment air boundary check valve to pass a back leakage test could pre-vent the proper functioning of the salt water system. This event is discussed in section 3.D of this repor . Review of Licensee Event Reports (LERs) (90712 and 92700)

LERs submitted to NRC:RI were reviewed to verify that the details were

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clearly reported, including accuracy of the description of cause and ade-quacy of corrective actio The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted on site follow up. The following LER was reviewed:

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LER N Event Date Report Date Subject Unit 1 89-02 02/14/89 03/16/89 Improper Leads Lif ted on Containment Purge Valves No unacceptable conditions were note . Review of Periodic and Special Reports (90713)

Periodic and special reports submitted to the NRC pursuant to TS 6.9.1 and 6.9.2: were reviewed. The review ascertained: inclusion of information -

. required by the NRC; test results and/or supporting information; consis-tency with design predictions and performance specifications; adequacy of planned corrective action for resolution of problems; determination whether any . information should be classified as an abnormal occurrence; and validity of reported information. The following periodic reports were reviewed:

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February 1989 Operating Data Reports for Calvert Cliffs No. 1 Unit and Calvert Cliffs No. 2 Unit, dated March 10, 198 Report of Changes, Tests and Experiments dated, March 14, 198 Annual Report of Failures and Challenges to FORVs and Safety Valves for the Period January 1, 1988 through December 31, 1988, dated February 28, 198 Steam Generator Inspection Results Report, Unit.1 Steam Gener-ators 11 and 12 Eddy Current Testing Final Report for the period April-June,1988, dated February 24, 198 No unacceptable conditions were identifie . Licensee Action on Previous Inspection Findings (93702 and 92701)

(Closed) Unresolved Item (50-317/85-28-04) Hydrogen Recombiner Inspectio The inspector reviewed STP-M-581, Hydrogen Recombiner Inspection and determined that the procedure included provisions for documenting results of the inspection and acceptance criteria. This item is close (Closed) Unresolved Item (50-318/85-34-01) Temporary Procedure Change The inspector reviewed memorandum from operations personnel attesting that the GSN0 counseled all shift personnel on proper documentation of tem-porary procedure change In addition, formalized guidance was provided to shift personnel via GSN0 Standing Instruction 86-1 which was also reviewed. This item is close _ _ _ - _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _

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(Closed) Unresolved Item (50-318/85-32-02) Engineered Safety Features Actuatio The inspector reviewed General Supervisor of ' Nuclear Opera-tions Standing Instructions which specifies plant evolutions that required Senior Reactor Operator presence to ensure plant safety and operability of equipment. Among those evolutions is Engineered Safety Features Actuation System startup, shutdown and operations testing. This item is close (Closed) Unresolved Item (50-318/85-20-03) Failure to Follow Procedures for Environmental Qualification Inspection (EQ). The inspector has reviewed the licensee's files and found them to be in compliance with the procedures in question during previous EQ inspection This item is close (Closed) Inspector Follow Item (50-317/85-15-01) Salt Water Pump Suction Bell Erosion / Corrosion. The inspector reviewed maintenance orders for salt water pumps #13, 21 and 23 which occurred following the inspection of the above mentioned pumps during the third quarter of 198 The results showed no evidence of holes on the suction bells of the pump In addition, design engineering performed an analysis on the salt water pumps assuming gross degradation of the suction bells. The conclusions were that with the assumed gross damage, there would be sufficient strength remaining in the suction bells to resist seismically-imposed loads. This item is close (Closed) Unresolved item (50-317/85-03-02) Post Modification Testing of Reactor Trip Breaker The inspector reviewed a copy of CCI 200L, Appendix 200.30, Post Maintenance and Operability Testin The CCI clar-ifies Post Maintenance Testing requirements for all safety-related equip-ment. This item is close (Closed) Unresolved Item (50-318/87-28-01) Atmospheric Dump Valve (ADV)

Performance Proble Performance problem with #11 ADV was identified to be a lock nut on the stem loosening and becoming jammed in the packing gland. The licensee has removed the lock nuts from Unit 1 ADV's. The gasket material on the ADV's has been replaced with material capable of withstanding higher temperatures. In addition, the enclosures around the ADVs have been removed to reduce the temperature levels. Procedures have been developed to aid mechanics during the overhaul of the ADVs. This item is close . Unresolved Items (93702)

Unresolved items require more information to determine their acceptability and and one such item is discussed in section 8 of this repor . Exit Interview (30703)

Meetings were periodically held with senior facility management to discuss f the inspection scope and findings. A summary of findings was presented to

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