IR 05000313/1999012
| ML20211L507 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 09/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20211L496 | List: |
| References | |
| 50-313-99-12, 50-368-99-12, NUDOCS 9909080258 | |
| Download: ML20211L507 (14) | |
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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
50-313;50-368 License Nos.:
50-313/99-12,50-368/99-12 Licensee:
Entergy Operations, Inc.
Facility:
Arkansas Nuclear One, Units 1 and 2
Location:
1448 S. R. 333 Russellville, Arkansas 72801 Dates:
July 11 through August 21,1999 Inspectors:
R. Bywater, Senior Resident inspector
K. Weaver, Resident inspector Approved by:
P. Harrell, Chief, Project Branch D Division of Reactor Projects ATTACHMENT:
SupplementalInformation
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I 9909090258 990901 j
PDR ADOCK 05000313 O
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EXECUTIVE SUMMARY Arkansas Nuclear One, Units 1 and 2 NRC Inspection Report 50 313/99-12; 50-368/99-12 This routine announced inspection included aspects of licensee operations, engineering, t
maintenance, and plant support. The report covers a 6-week period of resident inspection.
Operations Unit 2 operators quickly responded and evaluated plant risk when the turbine-driven
Emergency Feedwater Pump 2P-7A tripped on overspeed during surveillance testing.
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Control room operators made the conservative decision to leave the pump's mechanical
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overspeed trip device in the as-found tripped condition and quickly captured pump data
in order for the engineering staff to evaluate the cause of the pump's erratic speed j
oscillations and mechanical overspeed trip (Section M1.2).
Unit 1 operators responded promptly and effectively to alarms and plant conditions
resulting from rapid degradation of Makeup Pump P-36A (Section O2.2).
Maintenance Housekeeping in the Unit 2 emergency diesel generator room ventilation air intake and
exhaust fan area pit was poor. Foreign material had the potential to clog the roof drains and allow rainwater to enter into both emergency diesel generator rooms at the same time through the air intake louvers. An engineering evaluation concluded that this problem would not affect operability of the emergency diesel generators (Section O2.1).
Before commencing work on the Unit 1 Makeup Pump P-36A, maintenance personnel
were informed that an air sample had been taken and analyzed for hydrogen gas earlier.
However, the health physics technician covering the work activities demonstrated added i
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precaution and attention to detail by again questioning the personnel involved to verify that an air sample had been taken and that no hydrogen gas was present in the arec. It was determined that a sample was not taken for this job in accordance with the work instructions. The sample taken was for another job in another location in the Unit 1 auxiliary building (Section M1.1).
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Engineering and maintenance personnel provided good technical support and expertise
in determining and evaluating all possible causes for the overspeed trip of the Unit 2 turbine-driven Emergency Feedwater Pump 2P-7A. Their efforts and quick response
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resulted in reducing the amount of time that the pump was declared inoperable and unavailable to perform its safety function (Section M1.2).
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-2-Plant Sucoort '
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During the grinding activities on Unit 1 Makeup Pump P-36A,'the health physics technician continued monitoring for airborne contamination and surface contamination levels..The maintenance craft performing the work demonstrated good radiological worker practices and complied with the radiation work permit requirements, as well as additional precautions requested by the health physic technician (Section M1.1).
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Rooort Details L
Summarv of Plant Status Unit 1 began the inspection period at 100 percent power. On July 19,1999, operators reduced reactor power to approximately 80 percent in preparation for the Circulating Water Bay B and l
Service. Water Bay A maintenance outage.~ Operators returned Unit 1 to 100 percent power the
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same day. ;On August 6, operators reduced reactor power to approximately 85 percent for turbine valve and governor valve testing. Operators returned Unit 1 to 100 percent power the; same day., Unit 1. remained at or near 100 percent power through the remainder of this -
inspection period.
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Unit 2 began the inspection period at 100 percent power. On August 21,1999, operators reduced reactor power to approximately 92 percent for turbine valve and governor valve testing.
Operators returned Unit 2 to 100 percent power the same day. Unit 2 remained at or near 100 percent power through the remainder of this inspection period.
1. Operations
Conduct of Operations
'01.1 General Cornments (71707)
The inspectorc observed various aspects of plant operations, including shift manning, to verify compliance with Technical Specifications (TS), plant procedures and the Updated Safety Analysis Report (USAR). Inspectors also observed the effectiveness of communications, management oversight, proper system configuration and configuration control, housekeeping, and operator performance during routine plant operations and surveillance testing.
The conduct of operations was professional and safety conscious. Evolutions were
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generally well controlled and performed according to procedures.- Shift turnover briefs
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were comprehensive. Housekeeping was generally good and discrepancies were promptly corrected. Safety systems were found properly aligned. Specific events and noteworthy observations are detailed below.
O1.2'. Unit 1 - Nonlicensed Operator Rounds
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' On July 27,1999, the inspectors accompanied the Unit 1 nonlicensed operator in j
charge of the outside areas on his routine shift rounds. - The tour included the Unit 1 l
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. intake structure, transformer yard, and the emergency cooling pond. The inspectors
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' found the nonlicensed operator knowledgeable of the equipment and his duties and
' responsibilities. The nonlicensed operator appropriately recorded all required equipment parameters and instrument readings. The inspectors found that housekeeping in these areas was good, l
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Conclusions The Unit 1 nonlicensed operator in charge of the outside areas was knowledgeable of the equipment and his duties and responsibilities. Housekeeping in the Unit 1 intake structure, transformer yard, and emergency cooling pond areas was good.
Operational Status of Facilities and Equipment O2.1 Unit 2 - Trash and Debris in the Emeraency Diesel Generator (EDG) Room Ventilation intake and Exhaust Fans Area Pit a.
inspection Scope (71707)
The inspectors conducted a tour of the Unit 2 EDG room ventilation intake and exhaust fans area pit on the roof of the auxiliary building to ascertain the material condition of this equipment and housekeeping in the area.
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Observations and Findinas On July 21,1999, during a tour of the Unit 2 EDG room ventilation air intake and exhaust fan area, the inspectors noted a roof drain in the center of the pit near the Unit 2 EDG room ventilation air intake louvers. The inspectors noted that the drain appeared to be potentially clogged with trash and foreign material. The inspectors also noted that paper towels, rags, a large piece of plastic, nuts, bolts, and pieces of metal were on the pit floor. The inspectors also noted that it appeared that water from previous rainfall had transported debris into the lower portions of the air intake louvers in the corners of the pit. The pit was a common area for room ventilation for both EDG trains. The inspectors were concerned that during significant amounts of rainfall, with the roof drain clogged, water would fill the open air intake pit and overflow through the EDG air intake louvers into both EDG rooms at the same time, which could potentially render both Unit 2 EDGs inoperable from a common event. The inspectors questioned the licensee's engineering staff concerning their analysis for a postulated maximum probable precipitation event. The inspectors also reviewed the Unit 2 USAR and noted that USAR, Section 2.4.3.7 stated that, "There are some minor isolated areas where water could pond as in the case of a clogged drain; however, there are no openings through which even ponded water could enter a Seismic Category 1 structure." During walkdowns of both Unit 2 EDG rooms, the inspectors noted that the EDG control cabinets were sitting approximately % to 1 inch up from the floor, therefore, flooding of water on the floor in either of the EDG rooms could potentially disable these control cabinets.
The licensee initiated Condition Report (CR) 2-1999-0521 to document this concern. As part of the licensee's immediate corrective action, rnaintenance craft cleaned the Unit 2 EDG air intake pit area and roof drains. The inspectors were subsequently informed that there were actually two roof drains in the air intake pit area.
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. The licensee's engineering staff performed an operability evaluation for draine from l
the air intake pit into both the EDG rooms. The licensee concluded, based on a calculation of the amount of water that could enter the room during a postulated
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maximum probable precipitation event, that it was possible to flood the EDG rooms to
% inch, if the EDG room floor drains were functional. The licensee stated that this would not affect any safety-related equipment in the EDG rooms. The licensee documented a i
discrepancy report for USAR, Section 2.4.3.7, for evaluation and possible revision.
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Conclusions Housekeeping in the Unit 2 EDG room ventilation air intake and exhaust fan area pit was poor. Foreign material had the potential to clog the roof drains and allow rainwater to enter into both EDG rooms at the same time through the air intake louvers. An engineering evaluation concluded that this problem would not affect operability of the emergency diesel generators.
O2.2 Unit 1 - Makeuo Pumo P-36A Failure (71707)
On July 23,1999, Unit 1 operators received a motor winding temperature high alarm in the control room for Makeup Pump P-36A. The operators observed other indications of degrading pump performance including reduced reactor coolant pump seal injection flow and increasing makeup tank level. Operator actions in response to the transient included starting the standby Makeup Pump P-368, stopping Makeup Pump P-36A, and throttling open Seal Injection Flow Control Bypass Valve MU-1207-3 to maintain adequate sealinjection flow.
The cause of the pump failure was rubbing between the impeller and the pump casing.
Foreign material trapped in the internals of Seal Injection Flow Control Valve CV-1207
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contributed to the reduction in seal injection flow, which necessitated opening Bypass Valve MU-1207-3. Seal Injection Flow Control Valve CV-1207 was repaired and returned to service on July 25. The scope of repairs for Makeup Pump P-36A included replacing the rotating assembly and blending the rubbed areas of the pump casing. The pump was returned to an operable status on August 8.
Conclusions Unit 1 operators responded promptly and effectively to alarms and plant conditions resulting from rapid degradation of Makeup Pump P-36A.
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' 11. Maintenance I
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' Conduct of Maintenance i
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Insoection Scoce (62707)-
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The inspectors observed the following maintenance activities as identified by the L
following maintenance activity instructions (MAI):
MAI 12703, Unit 1 P-36A Makeup Pump Disassembly / Repair, performed on
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- July 28 (Unit 1).
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L Observations and Findinas During review of MAI 12703, the inspectors noted that a scope addition had been added i
to.the MAI to allow the repair of the upper and lower pump casing of the P-36A Makeup
- Pump using a hand grinder. The inspectors noted that maintenance personnel were l
preparing the job site for this grinding activity. The inspectors also noted that the scope j
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addition contained a caution /waming that stated, "This system contains Hydrogen and
due to its extremely flammable and explosive nature, special precautions should be taken before grinding. Safety to sample for Hydrogen Gas and periodically check
. thereafter per craft supervisor dir.ections." The inspectors questioned maintenance and health physics personnel at the job site if they had sampled for hydrogen gas. After conversations over the telephone with another health physics technician, personnel at the job site stated that the sample had been taken earlier and that no hydrogen gas was identified. The maintenance technicians and the health physics technician performing the job coverage continued to prepare the work site for the grinding activities.
' Subsequently, the maintenance personnel dressed out in anticontamination clothing and
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entered into the work area to commence the grinding on the pump casings. The health physics technician covering the work activities demonstrated added precaution and attention to detail by again questioning the personnel involved to verify a sample was
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taken and no hydrogen gas was present in the area. After conversation among the health physics personnel and the maintenance craft involved, they determined that an air sample was not taken for this job in accordance with the work instruction. The sample that was taken and analyzed earlier was for another job in another location in the. Unit 1 auxiliary building, Subsequently, an air sample was taken and no hydrogen gas was present. The inspector observed, during the grinding activities, that the health physics technician provided good radiological job coverage. The health physics technician continuously
monitored for airborne contamination and surface contamination levels. The maintenance craft performing the work demonstrated good radiological worker practices i
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and complied with the radiation work permit requirements as well as additional
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precautions requested by the health physics technician.
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Conclusions Before commencing work on the Unit 1 Makeup Pump P-36A, maintenance personnel were informed that an air sample had been taken and analyzed for hydrogen gas earlier.
However, the health physics technician covering the work activities demonstrated added precaution and attention to detail by again questioning the personnel involved to verify that an air sample had been taken and that no hydrogen gas was present in the area. It was determined that a sample was not taken for this job in accordance with the work instructions. The sample taken and was for another job in another location in the Unit 1 auxiliary building.
During the grinding activities on Unit 1 Makeup Pump P-36A, the health physics technician continued monitoring for airborne contamination and surface contamination levels. The maintenance craft performing the work demonstrated good radiological worker practices and complied with the radiation work permit requirements, as well as additional precautions requested by the health physics technician.
M1.2 General Comments on Surveillance Activities a.
Inspection Scope (61726)
The inspectors observed all or portions of the following surveillance activities:
Procedure 2106.006, Revision 49, " Emergency Feedwater System Operations,"
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Supplement 1,"2P-7A Quarterly Surveillance," performed on August 2 (Unit 2).
Procedure 1104.002, Revision 51-02, " Makeup and Purification System
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Operation," Supplement 3,"HPl Pump P-36A Test," performed on August 8 (Unit 1).
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Observations and Findinas Unit 2 - Turbine Driven Emeroency Feedwater (EFW) Pumo 2P-7A The inspectors observed the surveillance testing of the Unit 2 turbine-driven EFW Pump 2P-7A, performed on August 2. The inspectors noted that the control room operators appropriately declared the Unit 2 EFW Pump 2P-7A inoperable and entered the TS 3.7.1.2 action statement. Good communication was also noted between the control room and the nonlicensed operator in the field during preparation for this test.
The inspectors observed that, when EFW Pump 2P-7A was started, the pump displayed a normal speed profile on the plant monitoring system computer. Approximately 15 minutes into the run, the inspectors observed that the reactor operator manually adjusted the pump speed downward to 3700 rpm using the Speed Control Potentiometer 2 HIC-0336-2, in accordance with step 2.20 of Procedure 2106.006. At this time, EFW Pump 2P-7A speed started to oscillate erratically and then tripped on i
ovraped.
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-6-The inspectors observed that Unit 2 operators immediately evaluated plant risk based on EFW Pump 2P-7A unavailability, which was determined to be increased from minimal to moderate risk. The operators then commenced restoring normallineup for the EFW Pump 2P 7A with the exception of the mechanical overspeed trip device. The control room operators made the conservative decision to leave the pump in a tripped condition in order for the licensee's engineering staff to evaluate the as-found condition.
The licensee immediately initiated CR 2-1999-0525. The inspectors attended the event response team meeting that was conducted before the troubleshooting activities to evaluate all possible causes for the EFW Pump 2P-7A speed oscillations and mechanical overspeed trip. The inspectors noted that several of the licensee's design and system engineering, operations, maintenance, and management personnel were l
present at the meeting to provide technical support and expertise to determine and evaluate all possible causes of the event.
The licensee determined that the Speed Control Potentiometer 2 HIC-0336-2 was faulty, and it was subsequently replaced. In addition, the licensee performed three consecutive i
mechanical overspeed trip tests and determined that the system nas operating as required. The quarterly surveillance test was subsequently performed again on August 3 and EFW Pump 2P-7A successfully passed the test. The control room operators then declared the pump operable and exited the TS 3.7.1.2 action statement.
Unit 1 - Makeuo Pumo P-36A
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The inspectors reviewed the adequacy of the postmaintenance test procedure used to demonstrate operability of Makeup Pump P-36A. The routine quarterly surveillance test of Makeup Pump P-36A, used to satisfy inservice testing program requirements during power operation, only collected pump performance data at a single low-flow operating point. Because of the extensive maintenance performed on Makeup Pump P-36A, the licensee revised Procedure 1104.002, Supplement 3, to include installation of an additional flow instrument to provide capability of measuring pump recirculation flow and collection of pump performance data at additional points on the pump performance curve. Plant operating conditions precluded performing a full-flow test, which would normally be expected following significant pump maintenance. The inspectors considered the licensee's revision of the test procedure to collect additional pump performance data, given plant operating conditions, consistent with an effective postmaintenance inservice testing program. The licensee informed the inspectors that a full flow performance test of Makeup Pump P-36A would be performed during the fall 1999 refueling outage.
The inspectors observed portions of the testing, reviewed the pump performance data and engineering evaluation of the results, and concluded that the licensee's actions to return Makeup Pump P-36A to an operable status were acceptable.
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Conclusions Unit 2 operators quickly responded and evaluated plant risk when the turbine-driven Emergency Feedwater Pump 2P-7A tripped on overspeed during surveillance testing.
Control room operators made the conservative decision to leave the pump's mechanical overspeed trip device in the as-found tripped condition and quickly captured pump data in order for the engineering staff to evaluate the cause of the pump's erratic speed oscillations and mechanical overspeed trip.
Engineering and maintenance personnel provided good technical support and expertise in determining and evaluating all possible causes for the overspeed trip of the Unit 2 turbine-driven Emergency Feedwater Pump 2P-7A. Their efforts and quick response resulted in reducing the amount of time that the pump was declared inoperable and unavailable to perform its safety function.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Unit 2 - Containment Coolino Fan 2VSF-1 A
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Inspection Scope (71707. 62707,61726. 37551)
The inspectors reviewed and observed portions of the licensee's activities in response to i
declaring the Unit 2 Containment Cooling Fan 2VSF-1 A inoperable on August 9.
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Observations and Findinas The licensee's predictive maintenance organization identified elevated vibration readings indicative of motor bearing degradation on the Unit 2 Containment Cooling i
Fan 2VSF-1 A on February 8, and documented this condition in CR 2-1999-0243. The vibration was determined to not affect operability of the fan and the licensee initiated an mal to inspect and repair the fan during the 1999 Unit 2 midcycle outage. Followup periodic vibration monitoring confirmed a continuing trend in bearing degradation and the licensee documented this trend in CRs 2-1999-0450 and 2-1999-0532. Both CRs concluded that the fan was operable. On August 9, another set of vibration readings were collected and the licensee concluded that the rate of bearing degradation had increased and that there was no longer assurance that the fan would be capable of performing its safety function for its mission time without catastrophic bearing failure.
j The licensee declared Containment Cooling Fan 2VSF-1 A inoperable and entered
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TS Action Statement 3.6.2.3.a for having an inoperable containment cooling group (red train).
TS 4.6.2.3 identified operability requirements for the containment cooling groups.
TS 4.6.2.3.a.1 required a service water flow rate of at least 1250 gpm to each group of cooling units; each unit within the group having an operable fan, or a service water flow rate of at least 1250 gpm to one unit within the group; that unit having an operable fan.
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-8-The licensee pursued two parallel paths to restore operability of the red train containment cooling group. The first was development of a work plan to replace the Containment Cooling Fan 2VSF-1 A motor bearing and/or motor. The second was development of a work plan to divert service water flow from Containment Cooling Coil 2VCC-2A, the affected cooiing unit, to Containment Cooling Coil 2VCC-28, the remaining cooling unit in the red train containment cooling group with an operable fan, to achieve adequate service water flow. The containment cooling coils did not have isolation or flow control valves to divert flow from one cooler to another. Therefore, the licensee's work plan included the installation of blank flanges on the service water supply piping to Containment Cooling Coil 2VCC-2A to divert all red train containment.
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cooling service water flow to Containment Cooling Coil 2VCC-28.
The licensee proceeded with implementation of both of these methods of restoring red train containment cooling group operability concurrently. The inspectors reviewed the work plans, TS compliance, safety evaluations, postmaintenance testing requirements, and industrial safety issues. The inspectors attended plant safety committee meetings and infrequently performed evolution briefings for operations, engineering, maintenance, and radiation protection personnel. The inspectors had questions regarding containment integrity, postmaintenance testing, and operability requirements for the service water flow diversion option, which were either adequately addressed or turned over to an NRC safety system engineering inspection team, who was onsite at the time, for resolution. The licensee's plant safety committee meetings, work plan development, and briefings were implemented effectively and with an appropriate concern for nuclear and personnel safety.
The licensee installed the blank flanges for the service water supply to Containment Cooling Coil 2VCC-2A, but had not completed the engineering evaluation of the postmaintenance test results before completion of Containment Cooling Fan 2VSF-1 A repairs and testing. Therefore, the licensee elected to remove the blank flanges from the service water piping and restore the original service water flow lineup to the red train containment cooling group. Postmaintenance testing was completed on August 15, and the red train containment cooling group was restored to operable status within the
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allowed outage time, M2.2 Unit 2 - Water Hammer Durina inservice Testina of Containment Cooler Isolation Valves a.
Inspection Scope (71707. 62707. 61726. 37551)
The inspectors reviewed and observed portions of the licensee's activities following a water hammer event that occurred during inservice testing of the Unit 2 containment cooler service water isolation valves.
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Observations and Findinas At 1:55 a.m. on August 18, during performance of Procedure 2305.005," Valve Stroke and Position Verification," Revision 19-03, Supplement 1, " Quarterly Containment isolation Valve Stroke Test," a water hammer event occurred during stroke testing of the green train containment cooling group service water containment isolation valve.
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Control room operators stroked open and closed Valve 2CV-1513-2, the service water return containment isolation valve from Containment Coolers 2VCC-2C and 2VCC-2D.
Then, when control room operators stroked open Valve 2CV-1510-2, the service water supply containment isolation valve, the control room received service water header low pressure alarms for both trains of service water and a low Train B EFW service water supply pressure alarm. Also, the control room operators heard water hammer noise in the control room. The operators immediately closed Valve 2CV-1510-2 and initiated CR 2-1999-0551. No indications of water leakage were observed in containment as indicated by containment sump leak rate or humidity. Operators also walked down both trains of service water header piping in the auxiliary building and did not identify anything unusual.
Later on day shift, engineering personnel performed a walkdown of service water piping inside the Unit 2 containment building and did not identify any evidence of pipe movement or piping / piping support damage. Based on these walkdowns and an l
engineering evaluation, the licensee concluded that the service water piping and containment coolers were operable. The shift superintendent approved the operability evaluation on August 19 at 12:09 a.m. The inspectors turned over the review of the engineering evaluation of the water hammer event to an NRC safety system engineering inspection team that was onsite at the time of this event.
During the walkdown inside containment, the licensee identified a pinhole leak on the service water supply piping to Containment Cooler 2VCC-2D. The licensee concluded that the smallleak did not constitute a containment cooling operability concern. Instead, it was identified as a containment integrity concern because the containment isolation boundary for the containment coolers is the service water system piping, which will not be pressurized above peak containment pressure at all times following a design basis accident. Therefore, the licensee deenergized the containment isolation valves for the
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green train of containment cooling in the closed position to ensure containment integrity was maintained. The licensee developed a work plan to perform a code repair of the piping. During this repair effort, the plant was in a TS action statement, as required by TS 3.6.2.3. The licensee completed the repair and returned the green train of containment cooling to an operable status on August 20.
The inspectors had a concern with the licensee's operability determination process associated with this event. When the inspectors entered the Unit 2 control room on day shift and learned about the event that had occurred, the shift superintendent informed the inspectors that a CR had been initiated and that engineering personnel would provide assistance in evaluating the event for operability. The inspectors also learned that a routine test of the opposite train EDG was scheduled and planned to be performed that morning. The inspectors were concerned that, although there was no obvious indication of a service water or green train containment cooling problem, there had been no documented assessment of the ability of the green train containment cooling group to perform its safety function following the water hammer event. The inspectors noted that performing the surveillance test of the red train EDG, which makes it inoperable for a period of time, would result in emergency power being unavailable to the group of containment coolers that were redundant to the group that was potentially inoperable. The inspectors asked the shift superintendent if he believed it was prudent I
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-10-to perform the red train EDG surveillance due to uncertainty regarding the status of the green train containment coolers. Upon further discussion, the licensee elected to defer the EDG surveillance test until the containment cooler operability issue was resolved.
The inspectors were concerned that the licensee's operability determination process may allow licensed operators to consider equipment operable following identification of an issue that results in questions regarding operability of the equipment that the onshift licensed operators are unable to answer. The inspectors will continue to review the licensee's operability determination process on a ongoing basis.
111. Enaineerina E1 Conduct of Engineering Examples of engineering activities reviewed during this inspection period are addressed in other sections of this inspection report.
IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 General Comments (71750)
During routine tours of the plant and observations of plant activities, the inspectors found that radiation protection personnel were properly performing their duties, that access doors to high radiation areas were properly locked, and areas were properly posted.
S1 Conduct of Security and Safeguards Activities S t.1 General Comments (71750)
During routine tours of the plant and observations of personnel access into the protected area, the inspectors found that security personnel were properly performing their duties and that access barriers to vital areas were properly locked.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of the licensee's staff at the conclusion of the inspection on August 24,1999. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any material examined during the inspection should be considered proprietary. No proprietary information was identifie _
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ATTACHMENT PARTIAL LIST OF PERSONS CONTACTED Licensee C. Anderson, General Manager, Plant Operations G. Ashley, Licensing Supervisor B. Bement, Unit 2 Plant Manager.
T. Chilcoat, Radiation Protection Superintendent E. Christian, Unit 1 Instrumentation and Control Superintendent R. Cooper, Unit 2 Operations P. Dietrich, Unit 1 Maintenance Manager B. Gordon, Unit 2 Mechanical Superintendent G. Hettel, Unit 2 System Engineering B. James, Outage, Planning and Scheduling R. Partridge, Chemistry Superintendent D. Phillips, Unit 1 Supervisor.
S. Pyle, Licensing Specialist A. Remer, Unit 1 Mechanical Coordinator D. Sealock, Supervisor, Training B. Smart, Unit 2 Instrumentation and Control Coordinator C. Turk, Mechanical / Civil / Structural Engineering Manager J. Vandergrift, Director, Nuclear Safety R. Walters,' Unit 1 Operations Manager (Assistant)
C. Zimmerman, Unit 1 Plant Manager INSPECTION PROCEDURES USED 37551 Onsite Engineering 61726 Surveillance Observations 62707 Maintenance Observations 71707 Plant Operations 71750 Plant Support Activities LIST OF ACRONYMS USED CFR Code of Federal Regulations CR condition report EDG emergency diesel generator EFW emergency feedwater MAI maintenance activity instruction NRC Nuclear Regulatory Commission TS Technical Specification USAR Updated Safety Analysis Report ITEMS OPENED. CLOSED. AND DISCUSSED
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