IR 05000321/1996013
| ML20135C369 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 11/25/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20135C297 | List: |
| References | |
| 50-321-96-13, 50-366-96-13, NUDOCS 9612060275 | |
| Download: ML20135C369 (57) | |
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U.S. NUCLEAR REGULATORY COMMISSION i
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REGION II
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Docket Nos: 50-321. 50-366 i License Nos: DPR-57 and NPF-5
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- Report No
- 50-321/96-13, 50-366/96-13 i
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l Licensee: Georgia Power Company (GPC)
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Facility: E. I. Hatch Units 1 & 2 Location: P. O. Box 439 Baxley. Georgia 31513
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Dates: September 15 - October 26. 1996 )
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Inspectors: J. Moorman. Senior Resident l Inspector (Acting)
E. Christnot. Resident Inspector J. Canady. Resident Inspector N. Merriweather. Reactor Inspector (Sections E2.3. E2.4. E4.1. E4.2. E6.1.
E6.2. E7. E8.1. E8.2. E8.3)
R. Moore. Reactor Inspector R. Chou. Reactor Inspector M. Ernstes. Operator Licensing Examiner P. Steiner. Operator Licensing Examiner i (Sections 03.2. 05.1)
E. Girard Reactor Ins ector (Sections M8.2. E .7. E8.8)
Approved by: P. Skinner. Chief. Projects Branch 2 Division of Reactor Projects >
Enclosure 2 9612060275 961125 I PDR ADOCK 05000321 i G PDR i
EXECUTIVE SUMMARY Plant Hatch. Units 1 and 2 NRC Inspection Report 50-321/96-13. 50-366/96-13 This integrated inspection included aspects of licensee operations.
engineering. maintenance and plant support. The report covers a 6-week period of resident inspection. The report also includes the results of announced inspections of engineering and licensed operator requalification program activities by regional inspectors. A followup inspection for close out of items identified during inspections pursuant to Generic Letter 89-10. Safety-Related Motor-Operated Valve Testing and Surveillance was also conducted.
Ooerations e During an Engineered Safety Feature (ESF) walkdown of the Plant Service Water System, the inspectors observed that the licensee had identified a broken seismic restraint on Unit 1 and a small through-wall leak on an air release valve on Unit 2. Licensee efforts to identify problems were excellent. The ins)ectors observed no other equipment or component conditions tlat might have degraded plant safety performance. (Section 02.1)
e The "B" Control Rod Drive pump on Unit 1 was tri aped when a plant equipmerit operator opened its control power breacer while performing a clearance for the "A" CRD pump. (Section 04.1)
e The annunciator response procedure to address a high temperature condition in control rod drive mechanisms was identified as needing improvement. (Section 03.1)
e An inspection of the licensed operator requalification program was conducted. The licensee's requalification program complied with the requirements and standards of )lant procedures as well as the requirements of 10 CFR 55.59 for tie areas inspected. The licensee developed and administered examinations that effectively identified areas in need of improvement. Overall, remediation of operators was adequately completed. (Section 05.1)
Maintenance e Maintenance activities were generally completed thoroughly and professionally. Work packages were available at the jobsite and were actively used. (Section M1.1).
e Maintenance activities associated with the replacement of the Unit 2 Plant Service Water (PSW) minimum flow piping and replacement of the seismic restraint for the 1A PSW motor-to-pump connection piping were performed well and in a timely manner. (Section M1.2)
e The inspectors observed oil being used from a container that was not labeled, as required by plant procedures, during the Reactor Core Isolation Cooling System outage. (Section M1.3)
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e Observed surveillance activities were completed thoroughly and professionally. The coordination between O and the Health Physics personnel was good. perations.
(Section M3.1)Engineering, e The licensee's review of surveillance testing requirements related to Unit 2 air operated vacuum breaker butterfly valves in the reactor building-to-suppression chamber vacuum breaker system, determined that they had not been surveillance tested as required by TS 3.6.1.7.3. (Section M3.2)
Enaineerina e The engineering evaluation and analysis for the small leak in PSW air release valve on Unit 2 was reasonable and timely. The appropriate Technical Requirement Manual actions were taken. The compensatory actions were reasonable. (Section E1.2)
e An inspection of the temporary modifications program was conducted. Design controls for temporary modifications were good, as demonstrated by the low number and limited age of temporary modifications. Regulatory requirements for design controls were adequately implemented. (Section.E2.3)
e An inspection of the design change and plant modifications program was conducted. The inspectors concluded that the design changes and plant modifications were adequate. (Section E2.4)
e Engineering activity for identification and monitoring of equipment reliability demonstrated a good focus on operations issues. Periodic equipment reliability meetings provided a mechanism for inter-organizational involvement on equipment problems. Although some examples of ineffective corrective action were noted, several other examples demonstrated effective resolution of plant equipment problems. The ins)ectors concluded that the licensee's )lanned actions to resolve tie spurious tripping of 600 VAC areakers were reasonable and prudent.
(Section E4.1)
e An inspection of the backlog of open design change requests and minor design changes indicated that the licensee had been i effective in reducing and managing the backlog of design changes.
(Section E6.2)
e The setpoint changes for the molded case circuit breakers were accomplished in accordance with approved instructions with post adjustment testing and engineering oversight. (Section E1.1)
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e Discrepancies between electrical connection drawings and the actual plant configuration in Main Control Room Panels were identified. (Section E2.2)
e Engineering activities concerning the possible leak in the IB Residual Heat Removal Service Water Heat Exchanger were excellent.
(Section E2.5)
e The inspectors concluded that a type RMS 9 electrical breaker trip device was the most probable cause for the 1B Reactor Protection-System Motor Generator trip that occurred on October 8, 1996.
(Section E2.1)
Plant Sucoort e- The licensee continued to experience oversights in radiological control procedures related to releasing material from the Radiological Control Area (RCA). On.a routine monthly radiological controls survey of the scrap metal yard, the licensee discovered a minor amount of radioactive materials improperly stored there.
(Section R1.2)
e The inspectors concluded that simulation and scenario control during Emergency Preparedness (EP) exercises is an area that continues to need improvement. Command and control for the EP exercise in the Emergency Operations Facility and Technical Support Center were excellent. Command and control in the Operations Support Center continued to be poor. -(Section Pl.1)
e Communications and communication equipment malfunctions continued to present problems associated with offsite notifications during
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the EP exercises. (Section P3.1)
e Conduct of the fire drill performed as part of the EP exercise was good. Communications during the drill were hampered due to problems with the radios. (Section F1.1)
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L Report Details i
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Summary of Plant Status Unit 1 began the report period at 100% rated thermal power (RTP) and continued until October 5, when power was lowered to 80% in response to isolation of some "A" train heater drains (paragraph 01.2). Power was returned to 100% the same day and was maintained for the remainder of the report period.
Unit 2 began the report )eriod at 100% RTP. The unit operated at that ;
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power level until Septem)er 30 when, due to a leak on a feedwater heater !
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drain valve, power was reduced to 85% RTP to make repairs. The unit was returned to 100% RTP on October 1. The unit operated at 100% RTP throughout the remainder of the report period except for routine testing activities.
l I. Doerations 01 Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure (IP) 71707, the inspectors conducted !
frecuent reviews of ongoing plant operations. In general. the I concuct of operations was professional and safety-conscious.
Management continues to stress the importance of using three-part ,
communications, peer checks and SCOPE (Stop. Consider. Observe. '
Perform. Evaluate). Specific events and noteworthy observations are detailed in the section below.
01.2 Inadvertent Closina of Feedwater Heater Valve IN22-F020A a. Insoection SCoDe (71707) !
On October 5.1996. Unit 1 experienced level swings in the "A" train of the 8th, 7th and 5th stage feedwater heaters. All three ,
heaters automatically isolated after exceeding the hi-hi level !
isolation setpoint. The operators reduced reactor power to 80% in accordance with procedure 34AB-N21-001-1S: Loss of Feedwater Heating.
b. Observations and Findinas On October 5. operators received alarms on "A" train feedwater heaters which indicated a high level condition and had isolated.
i Control room o)erators dispatched maintenance and operations
- personnel to t1e heater control panels. Operators initiated the
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immediate actions of 34AB-N21-001-15 and reduced reactor power to 80% as directed by the procedure. Initial investigation into the
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event indicated that a motor operated valve. 1N22-F020A had closed. The valve is used for isolation aurposes and is opened or
closed only by a spring-return-to-center landswitch. There are no automatic closure signals to the valve. The valve functioned 1 properly and re-opened when operators took the handswitch to o)en.
j After the valve was opened, operators successfully re-establisled j flow through the isolated heaters and reactor power was returned to 100% at 6:06 P.M. To prevent 1N22-F020A from possibly re-closing before the cause of closure was determined, its power supply e
breaker was opened and racked out.
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c. Conclusions j The inspectors concluded that operator response to the transient
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was excellent. At the close of the inspection period, the
licensee had not determined why the valve closed.
2 02 Operational Status of Facilities and Equipment 02.1 Enoineered Safety Feature System Walkdowns (71707)
The inspectors used IP 71707 to walk down a representative sample a of the Plant Service Water (PSW) System components on Units 1 j and 2. The selected components included the pumps, motors.
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associated piping, and associated instrumentation and controls.
Components were located in the intake structure. Emergency Diesel Generator Building, and the control room.
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No deficiencies were noted in the system lineup and housekeeping was good. During the walkdown, the inspectors became aware that
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the licensee had discovered a very small leak through'the body of
, the air release valve for the 2D PSW pump (Section E1.2).
j Additionally. the ins)ectors observed that minimum flow piping on
- the Unit 2 PSW pumps lad been replaced and that a seismic
- restraint had broken on the suction 3iping of the 1A PSW pump.
i The 1A PSW pump was declared inoperaale when the seismic restraint broke on the suction piping. The restraint was replaced in a timely manner. The licensee requested and received ASME code 3 relief from the NRC concerning the PSW air release valve. This i allowed the licensee to leave the air release valve as is until i the next refueling outage. At that time, the valve is scheduled t
to be replaced. No other ecuipment or component conditions were
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This is further discussed in section M1.2 of this report.
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03 Operations Procedures and Documentation 03.1 Inadeauate Control Rod Drive Hydraulic System Ooeratina Procedure a. Insoection Scooe (71707)
While in the Unit 2 control room on September 14. the inspector noted that annunciator 140. "CRD HYD TEMP HIGH." on alarm panel 603-1 was in alarm. Unit 2 was stable at 100% power with no evolution in progress.
b. Observations and Findinas The inspector questioned the control room operators concerning the alarm and the status of the Control Rod Drive Hydraulic System.
The control board operator referred to annunciator response procedure (ARP). 34AR-603-140-2S. "CRD HYD TEMP HIGH." Revision 3.
Step 5.1 of this procedure states "If CRD cooling water flow and pressure are NOT within 20-41 GPM and 8-15 PSI respectively. THEN ADJUST them per 34S0-C-11-005-2S: Control Rod Drive Hydraulic System.- The control board has indication for CRD cooling water flow and differential pressure. At the time, cooling water flow was within the band, but differential pressure was 4 to 6 psid.
According to the operators, this is the normal value for cooling water differential pressure. The ARP also directs the operators to confirm the validity of the alarm by monitoring CRD temperature locally at the CRD temperature recorder. The reactor building plant equipment operator (PEO) was contacted and he confirmed the validity of the alarm and informed the control room that the temperature of rod 22-27 indicated 289 F. The alarm setpoint is 250 F. The PE0 stated that a deficiency tag documenting a high temperature condition for the affected rod was attached to the temperature recorder. The deficiency noted that rod 22-27 had experienced a high temperature condition after rod exercise testing conducted on August 10. 1996.
The inspector questioned the operators concerning the proper response.to the high temperature condition. The o)erators stated that it was not unusual for a CRD to experience a ligh temperature condition after performing rod exercise tests and that the condition would clear without operator action. After noting that the CRD cooling water flow differential pressure was not in the band provided by the ARP. the inspector questioned the operators concerning the procedure for raising it into the band provided by the ARP. A review of 34S0-C11-005-2S identified that the procedure did not provide guidance for increasing cooling water differential pressure. For operational considerations, both units have isolated the line that returns excess CRD flow back to the reactor. This alignment prevents the operators from adjusting CRD cooling flow differential pressure. The Shift Supervisor Enclosure 2
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initiated a deficiency card to get this procedure into the corrective action system. The Unit 1 procedure was similar.
c. Conclusions The annunciator response procedure was deficient in that it did not provide the operators with adecuate guidance to address an abnormal component condition. By cirecting the operators to raise cooling water differential pressure, the ARP directed the o)erators to perform an action that could not be accomplished with t1e CR0 system in it's normal alignment- By referring to .
" pressure" instead of " differential pressure" and " PSI" instead of
"PSID" Step 5.1 of the ARP contained errors that provide inadequate guidance to the operators.
The failure of ARP 34AR-603-140-2S to contain correct instructions for addressing a high temperature condition in . control rod drive i mechanisms is a violation of the requirements of 10CFR50.
A)pendix B. Criterion V. Instructions. Procedures and Drawings.
T1is failure constitutes a violation of minor safety significance and is identified as Non-Cited Violation. 50-366/96-13-01:
Inadequate Annunciator Response Procedure, consistent with Section IV of the NRC Enforcement Policy.
03.2 Emeraency Goeratina Procedures (EOP) (42001)
a. Jasp_ection Scooe The inspectors followed up IFI 50-321.366/96-10-08:
Clarification of E0P Step RC/P-3 Wording. The inspectors compared Revision 4 of the Boiling Water Reactor Owners Group Emergency Procedure Guidelines (EPG). the licensee's Plant Specific .
Technical Guidelines (PSTG), and the licensee's E0P with regard to !
the step in question. The inspectors reviewed the documentation i used to justify EPG to PSTG differences, and PSTG to E0P j differences. The ins '
management personnel,pectors interviewed trainingE0P andduringo)erationsand o requalification simulator scenarios.
b. Observations and Findinos
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EPG step RC/P-3 gives direction to depressurize the Reactor Pressure Vessel (RPV) and maintain cooldown rate below 100 F per !
hour after determining that the reactor is sufficiently shutdown.
Review of the EPG to PSTG document indicated agreement between the two guidelines with regards to ste) RC/P-3. However, the E0P and PSTG differed in this area. The clange was described in Revision 7 of the PSTG to E0P Comparison Document. Flow Chart i (FC) step RC(G2) was added prior to the E0P step associated with l- RC/P-3 of the EPG. The additional step stated. " WAIT until a
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reduction in RPV pressure is required." The facility had trained. l operators to use this step as a holding point during a small break :
I Loss of Coolant Accident (LOCA) with a concurrent loss of high j pressureinjection. The operators were trained to delay *
attempting to restore a high pressure injection source. RPV level !
would continue to decrease with no high 3ressure makeup sources available and RPV pressure higher than tie shutoff head of all low
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pressure injection sources. As observed during requalification i simulator scenarios, operators waited until RPV level reached Top of Active Fuel (TAF), and Emergency Depressurization (ED) was
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procedurally required. During the wait, the LOCA is dumping energy into the drywell and heating the suppression pool If depressurization were commenced immediately using Turbine Bypass iaives, as directed by the EPG guidance, the probability of I being able to inject with the Condensate System prior to reaching TAF will increase. It will also result in a lower initial RPV pressure if ED is eventually required and. hence, reduce thermal stress on the RPV and its components. A larger portion of the post shutdown energy would be dumped to the condenser vice the containment.
There appears to be a significant technical difference in mitigation strategy between the EPG and the E0P. The licensee believed that adding step RC(G2) merely clarified the intent of the RC/P section in flow chart format and did not involve a deviation from EPG guidance. The "PSTG to E0P Comparison Document." Revision 7, listed the following basis for the added step:
" Clarifies the intent of the RC/P section in flow chart format.
Training department verification recommendation WGW/89/06-002 and E0P Validation Training Comment #1."
The training and operations staff indicated that Verification Evaluation Discreaancy Sheet WGW/89/06-!LO2 was a t/pographical error and should lave been WGW/89/06-029. The inspectors reviewed discrepancy sheet WGW/89/06-029. It documented the following discrepancy: RC RCA-RC/P gives no direction to stop progression if Reactor Depressurization is not desired. The discrepancy sheet's suggested resolution was. "Give some direction on [the E0P flow] chart for exit from chart if entry conditions no longer exi st . " The remarks section noted, " Develop a cover procedure to provide some guidance on how to exit the E0Ps." This was done in 30AC-0PS-013-05: Use of Emergency 0)erating Procedures. This direction allowed exit of the E0Ps w1en entry conditions no longer existed or the Shift Supervisor (SS) determined that continued performance of E0P actions were no longer required to maintain the Enclosure 2
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plant in a safe condition. This guidance is for all E0P steps and did not justify the addition of step RC(G2).
In the discussion of emergency operating procedure entry and exit.
in EPG Appendix B, page B-4-16. the following guidance was given:
For example, the procedure developed from the RPV Control Guideline s)ecifies cooldown to cold shutdown conditions by various metlods and exit after the shutdown cooling interlocks -
have cleared, but entry into this procedure does not require any cooldown if it can be determined that an emergency no longer exists prior to establishing the conditions re commence the cooldown as specified in the procedure. quired to This guidance allows the operators to not proceed with any cooldown if an emergency no longer exists. With a small break LOCA in progress, and a loss of high pressure injection, an emergency does exist. The conditions which would preclude starting the cooldown as s)ecified in the procedure are Anticipatory Transient Wit 1out a Scram (AT4S) conditions. If an ATWS is not present, the cooldown should commence.
The inspectors reviewed Validation Training Comment #1. dated 8/20/89. This sheet gave the following discrepancy description:
@ G-2. change WAIT UNTIL statement to say " WAIT UNTIL cooldown is desired" to allow operator to stay at the step until he wants to cooldown. In the remarks section of this sheet, the reviewer agrees that a crew may want to wait and not immediately start a cooldown if they think that they can get out of the event while still at pressure. However, the document had no other reference to technical justification for allowing this. The Final Resolution simply stated: " Wait until a reduction in RPV pressure is required."
c. Conclusions Plant Hatch procedure 30AC-0PS-006-05: Verification Program for Emergency Operating Procedures, required documentation to justify deviations from EPG guidance. Significant technical differences a)peared to exist between the mitigation strategy of the EPG and tie E0P with regard to ste) RC/P-3. However, the licensee believed that adding step RC(G2) merely clarified the intent of the RC/P .section in flow chart format and did not process a deviation. The inspectors have closed IFI-50-321.366/96-10-08:
ened URI Clarification of E0P Step 50-321,366/96-13-02: E0PRC/P-3 Deviationwording, From EPGand stephave RC op/P-3, until a technical conclusion can be made by the NRC to determine the safety significance of the difference between the EPG and the licensee's E0P mitigation strategies.
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04 Operator Knowledge and Performance 04.1 Inadvertent Trio of the 1B Control Rod Drive Pumo
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l l On October 1,1996, at 2:56 A.M., the Unit 1,1B Control Rod Drive
- (CRD) Pump tripped as the result of a plant equi) ment operator
! (PEO) deenergizing control power to it's supply ]reaker. At the j_ time,1B pump was operating to fulfill the function of the CRD j system.
'I b. Observations and'Findinas
! The inspectors' review of this activity identified that the IB CRD l pump tripped as a result of the PE0 improperly performing a
, clearance to support maintenance on the 1A CRD pump. There were
- two PE0's assigned to perform clearance 1-96-671. The handswitch i for the 1A CRD pump had already been tagged in the "stop" i aosition. The su) ply breakers, including their control power
! areakers, for bot 1 CRD pumps are located in the diesel building and are in separate rooms within the building. When the PEOs j entered the diesel building, the PE0 holding the clearance paperwork proceeded with the clearance while the other PE0 stopped ( to get ear protection. The PE0 with the paperwork went to the j wrong room and o)ened the control power breaker.for the IB CRD i pump supply breacer. The other PEO. following closely behind, did j not have a copy of the paperwork and was unaware that the i incorrect room had been entered. Both PEOs heard the supply
] breaker open, recognized this as abnormal, and called the control i room. In coordination with the control board operator (CBO), the l control power breaker was re-closed and the IB CRD pump was restarted. According to plant logs no high temperature or low accumulator pressure alarms were received.
The Operations Department has instituted the SCOPE (Stop.
Consider. Observe. Perform, Evaluate) program and a " peer check" ,
program in an effort to minimize " wrong train" events such as this I one. The SCOPE 3rogram has been in effect for approximately 2 !
years and peer c1ecks have been in effect for approximately 6 !
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c. Conclusions The inspector concluded that inadvertent stopping of the CRD pump is a significant occurrence due to the pump's function of keeping the control rod drive accumulators pressurized and of providing cooling to the control rod drive mechanisms and the reactor recirculation pump seals. As required by step 8.7.1.3 of 30AC-OPS-001-0S: Control of Equipment Clearances and Tags.
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Revision 15. a clearance is to be performed by "... positioning components AND securing DANGER tags to the components indicated by MPL AND/0R LOCATION OF COMPONENT AND TAGGED POSITION / CONDITION in the sequence designated in TAG NO./B.V. 08 A.I." This failure to follow procedure 30AC-0PS-001-0S is -identified as an example of 50-321.366/96-13-03. Failure to Follow Procedure - Multiple Examples.
05 Operator Training and Qualification !
05.1 Licensed 00erator Reaualification Proaram (71001)
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a. Insoection Scoce I l
During the period October 7 - 11. 1996, inspectors reviewed the '
licensee's licensed operator requalification program. Specific areas of review included operating test administration, operating examination quality, documentation of results, and remediation.
b. Observations and Findinas The inspectors observed the administration of simulator examinations to two shift crews. Each crew received two scenarios. The licensee evaluators' grading was consistent with the inspectors' observations. The licensee evaluators effectively asked follow up questions based on operator aerformance. This enabled them to determine the cause for an o) served error and determine individual or generic program areas in need of improvement.
Operators successfully completed the critical tasks associated with the simulator evaluation scenarios. The licensee evaluators identified areas in need of improvement in each scenario. The inspectors observed generic problems in communications and classification of events using the Emergency Plan. These problems were also identified by the licensee evaluators.
Imprecise communications occasionally hindered the flow of communications between crew members. For example, during one of the simulator scenarios, drywell pressure was rapidly increasing due to a leak. The reactor operator reported "Look here.
[ pointing to the dry well pressure indicator] going up in pressure ;
fast". A short time later other operators observed system i configuration changes and questioned whether a LOCA signal had i been received due to increasing drywell pressure. Had the !
original operator re)orted the parameter he was observing, and what the value was tie other operators would not have to ask additional questions to the SS or wait for shift briefs to determine plant conditions. Several of the operators attempted to use the three part communications in which an order or information l
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was given by one operator, it was repeated by the second operator and then acknowledged by the original operator. However, some operators only used this system occasionally. The use of crew briefs was an effective communications practice. Shortfalls in communication created by the above )roblems were frequently resolved when the SS called a crew )rief reviewing the plant status and summarizing the mitigation strategy.
As part of the Simulator Evaluations, the Superintendent of Shift (SOS) was required to classify events in accordance with the procedure 73EP-EIP-001-05: Emergency Classification and Initial Conditions. Revision 11. dated 7/13/95. The SOS mis-classified the event in two of the four observed scenarios. In one of the scenarios, the SOS declared an Alert for a seismic event when a Site Area Emergency (SAE) was warranted. He noted that the criteria for an Alert had been met but failed to continue in the procedure and note that the SAE criteria had also been met. In another scenario, the SOS misinterpreted a series of "AND" and
"0R" statements in Section 20.3 and classified an event as a SAE when it was not warranted. In the latter case, other crew members corrected the error prior to any notification. A review of the licensee s Job Performance Measure (JPM) bank in the area of emergenc action level classification showed that there were only two unpu lished JPMs to test this during the JPM portion of the annual operating examinations. There were eight JPMs that were
)ublished in the open examination bank. These eight JPMs have
)een used each year since 1991 without modification. A small number of JPMs in an open bank encourages operators to study only the JPMs and diminishes their effectiveness. This was made-evident by copies of these eight JPMs in 'a stack on an end table in the waiting area used by operators while waiting.for their annual exam. There were also bound volumes of the published JPM bank in the waiting area. The licensee's improvements to the Emergency Classification procedure and Emergency Classification testing methods will be tracked as IFI 50-321.366/96-13-04:
Inability to correctly classify events.
The inspectors reviewed the documentation of remedial training for operators that failed the examination or needed improvement. The documented remediation, for the operator who failed, adequately addressed the weaknesses observed by the inspectors. The licensee was also provided remediation for operators that needed improvement but did not fail.
During review of the annual requalification training curriculum outline. the inspectors identified that equal simulator training was provided for t.hift operators and staff operators.
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c. Conclusions
The inspectors concluded that the licensee's recualification ;
program complied with the requirements and stancards of plant l procedures as well as the requirements of 10 CFR 55.59 for the l areas inspected. The licensee developed and administered !
examinations that effectively identified areas in need of -
l improvement. Overall, remediation of operators was adequately l completed.
07 Quality Assurance in Operations j 07.1 Licensee Self-Assessment Activities a. Insoection Scooe (40500) l At the request of the Operations Manager, an internal assessment of the Hatch Operations Department was conducted during the week of September 16. The nine-member assessment team consisted of Jersonnel from the Hatch site, as well as personnel from Southern iuclear Operating Company and other utilities.
b. Observations and Findinas The team made assessments in the following areas: safety focus, management involvement problem identification problem resolution, quality of operations, programs and procedures. l operations efficiencies. The team report documented both positive 1 and negative observations. Areas identified for improvement were !
surveillance tracking, shift turnover practices, response to and control of annenciators, and communications. The report also made observations regarding the large backlog of procedure changes and the general quality of procedures, i
c. Conclusions The assessment documented observations that were consistent with 1 those made in the past by the inspectors. Interviews with ;
o)erations department managers indicated that they were reviewing t1e recommendations to determine the best way for implementation.
Overall, the assessment was a good indicator of the operations department's performance.
08 Miscellaneous Operations Issues (92700) (92901) ,
(Closed) VIO 50-321/96-04-01: Failure to Complete Technical
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08.1 Specification Surveillance Procedure for Secondary Containment 4 Integrity. I l
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i This violation was identified when a licensed shift supervisor ;
listed the wrong surveillance procedure to perform for l Surveillance Requirements 3.6.4.1.1 and 3.6.4.1.2. The supervisor i mistook the secondary containment test 3rocedure for the l containment integrity demonstration. T1e correct procedure was to l be performed every 31 days and the incorrect procedure was every .
18 months. Based on this the surveillance was erroneously deferred.-
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The inspectors reviewed the response.-dated May 21, 1996. ;
Personnel error was identified as the cause for the violation.
-The response also stated that the containment integrity demonstration was performed and that the individual involved was placed in the positive discipline program.
The inspectors also reviewed a document, dated September 25, 1996, from the operations manager to the various on-shift superintendents and supervisors. The document contained specific instructions to be followed to simplify the surveillance tracking process. Among the instructions were: the superintendent will review surveillances before deferral: the supervisor is responsible for the accuracy and quality of the surveillances and I will compare the surveillance task sheet to the surveillance schedule to ensure task sheets are not missing; the control board operator will independently evaluate the surveillance task and identify the correct procedure, section and equipment to be tested. Based on the reviews by the inspectors and the actions taken by the licensee this violation is closed.
08.2 (Closed) VIO 50-321.366/96-04-02: Failure to Follow Procedure.
This violation was identified when were in the " Operation Not Allowed" personnel region did not of the Power realize they Versus Flow Map when they received the Average Power Range Monitor (APRM) I upscale alarms.
The inspectors reviewed the response, dated May 21, 1996.
Personnel error was identified as the cause for the violation.
The response also stated that a contributing factor may have been a change to the APRM upscale alarm setJoint. Prior to the change.
operators would increase power until t1e upscale alarm was received. The new set point placed the power at or near the
" Operation Not Allowed" region. The response further stated that the involved personnel were counseled and that shift training was given to operations aersonnel regarding the event, it's causes, and consequences. T1e inspectors attended the shift training.
Based on the reviews by the inspectors and the actions taken by the licensee, this violation is closed.
l Enclosure 2 ;
!
_ _
08.3 (Closed) LER 321/96-02: Missed Technical Specification Surveillance on Secondary Containment Doors and Hatches.
l'
This item is discussed in paragraph 08.1 of this report. No new issues were revealed by the LER.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a. Insoection Scooe (62707) !
The inspectors observed all or portions of the following work activities:
-
MWO 1-95-2424: Repair EDG Building CO 2 Tank Valve l
-
MWO 2-96-2768: Clean RHRSW Strainer Loop B
-
MWO 2-96-1031: Change Oil in RCIC Pum) and Turbine
-
MWO 2-96-1035: Remove Test, Replace / Repair RCIC Suction I Relief Valve (2E51-F017)
-
MWO 2-96-2887: Evaluate Pin Hole Leak in PSW Air Release i Valve !
-
MWO 2-95-2099: Replace Unit 2 PSW Minimum Flow P1 ping :
-
MWO 2-96-2881: Cut and Realign PSW Minimum Flow Flange !
Connections !
-
MWO 1-96-3076: Replace Seismic Restraint on lA PSW Pump i b. Observations and Findinos tank valve repair.
The inspectors compensatory fire observed that during protection measures, sucthe C0[1 as fire hoses rigged in place and roving fire watches, were stationed in the EDG building.
During cleaning of the Unit 2 "B" RHRSW strainers, the inspector observed that approximately one gallon of debris was removed from !
the RHRSW strainer. The work was performed as a result of high '
strainer DP alarm in the CR.
Observations associated with the MW0s related to SSCs found in the ,
intake structure and the RCIC outage are discussed in sections l M1.2 and M1.3 respectively.
For all work observed, the inspectors found that the work was performed with the work packages present and being actively used.
The inspectors observed that during the implementation of the MDC.
the system engineer was present at the job site. Appropriate post l modification and maintenance tests were performed. These tests Enclosure 2
consisted of operating the equipment following the completion of work activities.
c. Conclusions on Conduct of Maintenance-Maintenance activities were generally completed thoroughly and professionally. No deficiencies were identified by the inspectors.
M1.2 Review of Plant Service Water Maintenance Work Activities a. Insoection Scooe (62707)
The inspectors reviewed the MW0s associated with the replacement of PSW minimum flow piping on Unit 2 and the replacement of a broken seismic restraint on the motor-to-pump connection piping of the 1A PSW pump. Portions of the work activity associated with replacement of the broken seismic restraint were observed, b. Observations and Findinas The inspectors observed that replacement piping had been installed on the minimum flow piping of Unit 2 PSW discharge piping while performing an ESF Walkdown of the system (Section 02.1). A review of MWO 96-2099 indicated that engineering made a recommendation to replace the piping due to wall thinning.
The inspectors reviewed the work package associated with MWO 96-3076. The work package provided the instructions for, replacing a seismic support band that supported the connecting piping between the 1A PSW pump and the motor. The problem was discovered on September 30 during outside rounds when a PE0 noticed excessive vibration of the pump. The pump was shutdown and the appropriate Required Action Statement (RAS) was entered. Maintenance replaced the seismic support band on October 2. The RAS was terminated after the pump performed satisfactorily during the post maintenance operability run.
c. Conclusion Licensee activities associated with the replacement of the Unit 2 PSW minimum flow piping and replacement of the seismic restraint for the 1A PSW motor-to-pump connection piping was performed in a timely manner. Work activities associated with the replacement of the seismic restraint were controlled and were performed in accordance with the associated work package.
Enclosure 2
, - . . . _ - .- - -.- -- . - - . . . - - - . _ - - . . - _ - -
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l I
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17 ;
l l M1.3 Reactor Core Isolation Coolina Maintenance Outaae l
! !
a. Insoection SCoDe (62707) !
The inspectors observed activities associated with the Unit 2 RCIC !
t outage. In conjunction with the observations, the inspectors !
l reviewed maintenance / operation procedures, the maintenance work I
packages, and held discussions with licensee personnel involved l with the work activities.
i ;
l b. Observations and Findinas !
l
! On October 8, the licensee began an online maintenance outage for l the Unit 2 RCIC System. The inspectors verified that the I
'
clearance tags for a representative sample of valves and breakers in the plant were properly hung. Additionally, a representative sampling of the clearance tags located on control switches in the control room were verified. It was also verified that the licensee had entered the appropriate RAS for the maintenance activities.
The inspectors observed ) art of the maintenance inspection activity on the RCIC tur)ine after it was disassembled. Through
'
discussions with maintenance personnel, the inspectors determined that no problems with the internals of the turbine were identified. Subsequent discussions with a maintenance supervisor for indications of any problems encountered at this point in the outage revealed that suction relief valve, 2E51-F017. had failed a bench leakage test. The valve was disassembled and re machining the seat and removing the buildup of scale. Thepaired valve by satisfactorily passed the bench leakage test after the repair activities.
On October 10. the inspectors attended the maintenance pre-job briefing for the performance of the RCIC turbine mechanical overs)eed trip test. The appropriate section of Procedure ;
52SV-E51-001-0S. RCIC Turbine Mechanical Overspeed Trip Functional '
Test and Calibration, Revision 2, was discussed. The pre-job briefing was thorough and the importance of effective communications and radiological / industrial safety were stressed.
Operations, maintenance, engineering health physics (HP) and ;
quality control (OC) personnel were present at the briefing. '
l l The inspectors observed the performance of the test locally in the ,
i RCIC Room. The test was conducted with the pum
[ the turbine and the reactor at rated pressure. p uncoupled from l i
The inspectors observed that local operations personnel had
! established communications with the control room and were
! performing the mechanical overspeed trip testing in accordance
j Enclosure 2 i
i
.i . .
< , . , , , . , - - - . - _-
. . . = - - , , -
__ _ _ _ _ _ . _ _ _ . _ . _ . _ _ . _ _ _ _ _ _ . . _ . - _ . _ . _ _-
with appropriate procedures. .The inspectors also observed that OC personnel were ) resent to witness the QC hold points identified in procedure 52SV ~51-001-0S.
- The inspectors observed several unmarked one gallon plastic
!
containers on the RCIC room floor. One of the containers was about half full of oil that was used to lubricate the turbine L bearings. The inspectors reviewed procedure 51GM-MNT-017-05:
i Control of Lubricants. Revision 1. Section 7.2.4 of this l procedure states that lubricant containers and grease guns will be marked so that the lubricant contained therein is easily identified. This observation was discussed with maintenance l
personnel. The inspectors were informed that the oil is stored in ;
- fifty-five gallon containers in the warehouse and that maintenance '
personnel will place the oil in smaller containers for convenience. ,
!
The inspectors visited Warehouse 6 to discuss with warehouse !
l personnel the process used for labeling lubricant containers- . The inspectors were informed that when lubricant is issued in smaller containers, the 3erson in the warehouse issuing the lubricant would place a la)el on the container. The inspectors observed a fifty-five gallon drum that held containers similar to the ones observed in the RCIC room. Most of the containers for disposal had labels on them, but the ins)ectors observed at least two containers with no labels that lad the residue of what appeared to be clean oil.
,
The inspectors inquired about the control of grease guns as referenced in procedure 51GM-MNT-017-0S. The inspectors were shown the location in Warehouse 6 where the grease guns are stored. The inspectors observed that all of the . grease guns in the storage location had labels affixed to them.
Subsequent discussions with maintenance supervision irdicated that the container observed by the inspectors was unlabeled because it ,
contained oil from a labeled five- gallon container. The oil in the labeled five-gallon container had been filtered to remove any possible moisture content. Oil from this container was poured into the one- gallon container for convenience. Through an oversight, maintenance personnel failed to label it. As immediate i
corrective action, maintenance supervision indicated to the l inspectors that the importance of using lubricant from properly
labeled containers will be stressed to each maintenance team j during the next shift team meetings.
I c. Conclusions
The inspectors concluded that the work activities observed were
- conducted in a safe and timely manner. The QC hold points were
i Enclosure 2
!-
f
!
, -_.r.. , - --
_ _ _ . _ _ . _ _ ._ _ _. _ _ _._ _ ._ _ . _ . _ ._._ _ ._ _~
i !
!
! 19 l performed as required by the procedure for the RCIC turbine- ,
mechanical overspeed trip test. The failure to follow procedure !
51GM-MNT-017-0S is identified as an example of '
50-321.366/96-13-03. Failure to Follow Procedure - Multiple Examples). ,
M3 Maintenance Procedures and Documentation M3.1 Surveillance Observations
!
a. Insoection Scooe (61726) !
The inspectors observed all or portions of the following Unit 1 and Unit 2 surveillance activities:
I 34SV-E51-002-1S: RCIC Pump Operability. Revision 17 I
34SV-R43-001-1S: Diesel Generator 1A Monthly Test.
Revision 17. edition 1 b. Observations and Findinas The inspectors attended the operations pre-job briefing for the RCIC Pump Operability surveillance. .The briefing was thorough and i the importance of effective communications and radiological / industrial safety were stressed. Representatives '
from HP and engineering were present. The Diesel Generator 1A Monthly Test was performed due to expected high winds in accordance with procedure 34AB-Y22-002-05. Naturally Occurring Phenomena. Revision 1.
The inspectors observed that local operations personnel had established communications with the control room and were performing the surveillance activities in accordance with appropriate procedures. There were no deficiencies identified with the performance of the surveillances.
c. Conclusions The observed surveillance activities were completed thoroughly and l professionally. The coordination between operations, engineering.
I and HP was good. Supervisory oversight and engineering i involvement was observed. Cleanliness control, material control i and radiation control measures were implemented as appropriate.
.
i I
1 l Enclosure 2 l
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M3.2 Missed Surveillance Reauirement l a ~. Insoection Scooe (617 M The inspectors reviewed the circumstances associated with the required TS surveillance on the' Unit 2 Reactor Building-to-Suppression Chamber Vacuum Breakers, valves 2T48-F310 and 2T48-F311. which had not been performed.
b. Observations and Findinas The licensee determined that as of 12:00 noon on September 17. air operated vacuum breaker butterfly valves 2T48-F310 and 2T48-F311 ,
had possibly not been surveillance tested as recuired by the TS to '
verify an opening setpoint of less than 0.5 psic. In accordance with SR 3.0.3, the licensee had 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to perform the surveillance and prove operability or enter an LCO.
The inspectors observed performance of the surveillance and reviewed the newly written procedure that was used. Both valves were tested and actuated within TS requirements. At 8:39 P.M. on September 17. Unit 2 exited SR 3.0.3.
The inspectors observed that after TSIP implementation, a surveillance procedure for the Unit 2 valves was not issued. This appears to be an oversight in the process of ensuring that all surveillance requirements were met with the implementation of the Improved Technical Specifications. A similar oversight was documented in NRC Inspection Report 50-321,366/96-10.
The inspectors reviewed the Unit 2 Technical Specifications.
Technical Requirements Manual and the Bases. Technical Specification 3.6.1.7, Reactor Building-to-Suppression Chamber i Vacuum Breakers, states "Each reactor building-to-suppression i chamber vacuum breaker shall be o)erable" and is applicable in l Modes 1, 2. and 3. Surveillance Requirement 3.6.1.7.3 requires the licensee to " Verify the o)ening setpoint of each vacuum breaker is equal to or less tlan 0.5 psid" with a frequency of 18 months. Unit 2 Technical Requirements Manual. Table T7.0-1.
Primary Containment Isolation Devices - Testable Penetrations, describes 2T48-F310 and F311 as normally closed, vacuum relief. 1 inboard, air operated butterfly valves. Unit 2 Bases B 3.6.1.7, Reactor Building-to-Sup)ression Chamber Vacuum Breakers, states in part "The function of t1e Reactor Building-to-Suppression Chamber Vacuum Breakers is to relieve vacuum when primary containment dearessurizes below reactor building 3ressure" It further states
"Tle design of the external (reactor )uilding-to-suppression chamber) vacuum relief provisions consists of two vacuum breakers (a mechanical vacuum breaker and an air operated butterfly valve),
located n series in each of two lines from the reactor building Enclosure 2
.. - - - .. - - .
I
i
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to the suppression chamber. The butterfly valve is actuated by differential pressure. The mechanical vacuum breaker is self actuating and can be remotely operated for testing purposes" l
l The surveillance procedure that ensures that Unit 1 air operated
, vacuum breaker butterfly valves comply with SR 3.6.1.7.3 l accomplishes this by performing what is defined in the TS as a '
l Channel Functional Test. The TS states "A CHANNEL FUNCTIONAL TEST shall be the injection of a simulated or actual signal into the l channel as close to the sensor as practicable to verify OPERABILITY, including required alarm, interlock, dis) lay, and trip functions, and channel failure trips. The CHANNEL FUNCTIONAL TEST may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is tested."
The air operated vacuum breaker butterfly valve is opened in the following manner. A differential pressure transmitter senses the pressure difference between the reactor building and the !
- suppression chamber. It then sends a signal to a device that i l converts current to voltage (signal converter). The voltage ;
l signal goes to an alarm module whose output causes a solenoid l valve to change position. The solenoid valve positions such that '
air can open the butterfly valve.
The inspectors reviewed procedures and records associated with both types of vacuum breakers for both units. From this review.
the inspectors determined that the surveillance testing or 3reventative maintenance performed for the mechanical vacuum areakers on both units and the air operated butterfly valve vacuum breaker for Unit 1 satisfied TS surveillance requirements.
However, this review failed to find evidence that the opening setpoint of Unit 2 vacuum breakers 2T48-F310 and 2T48-F311 was verified to be less than 0.5 psid. The review indicated that the differential pressure transmitters 2T48-N210 and 2T48-N211 had been calibrated on January 24 and 25. 1990, respectively. The frequency for the calibration was 5 years with a 100% grace period allowed. The signal converters and alarm modules for both A and B trains were calibrated on November 1, 1995. Prior to this, they were calibrated on October 6. 1992. The next due date was listed as November 1. 1998. The inspectors determined that a Unit 2 surveillance test butterfly valves, procedure such as thefor the air operated procedure for Unit 1.vacuum may notbreaker have been performed since the unit was licensed on June 13. 1978. The
.
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inspectors also found that personnel may not have considered the air operated butterfly valves as being part of the vacuum breaker
- system.
l l Surveillance Requirement 3.6.1.7.3 does not specifically require l that a CHANNEL FUNCTIONAL TEST be performed. However, for vacuum l Enclosure 2
.- - - . - -
l l
l
l breakers 2T48-F310 and 2T48-F311 to open at equal to or less than 0.5 psid. all components from the differential pressure transmitter to the air operated valve must function properly. The
,
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inspectors' review of activities associated with vacuum breakers 2T48-F310 and 2T48-F311 indicated that no single activity or
,
series of activities had been conducted within the required
- frequency to verify the opening setpoint of each vacuum breaker was equal to or less than 0.5 psid. as required by SR 3.6.1.7.3.
c. Conclusions ,
The failure to properly perform surveillance monitoring of 2T48-F310 and 2T48-F311 within the required frequency is identified as Violation 50-366/96-13-05. Failure to Properly Perform TS Surveillance 3.6.1.7.3.
M8 Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) VIO 321.366/96-04-02: Failure to Follow Procedure.
This violation was identified when, on two occasions, the inspectors observed clear plastic on the refueling floor.
The inspectors reviewed the response, dated V. 21, 1996, and observed that personnel error was stated as tne cause for the violation. The response also stated that contributing to the event may have been conflicting procedural requirements.
Procedures 51GM-MNT-002-05. Maintenance Housekeeping and Tool Control, and 210AC-MGR-021-05: Foreign Material Exclusion, did not provide consistent requirements. The first procedure did not require timely removal of clear plastic while the latter required removal as soon as practical. A temporary change to procedure 51GM-MNT-002-0S was made to require removal as soon as practical.
The inspectors reviewed the procedure and observed that Temporary Change 96-76 inserted step 5.2.6 which stated "J.E a clear item (s)
is received within a Foreign Material Exclusion (FME)
Area / Refueling (RF) Floor (e.g.. via receipt of packed boxes or shipping containers). THEN precautions must be taken to 3revent the inadvertent introduction of the clear item into the Reactor Coolant Pressure Boundary AND the item must be removed from the FME/RF Floor area as soon as practically possible." Based on the reviews by the inspectors and the actions taken by the licensee, this violation is closed.
M8.2 General Followuo on Motor-Ooerated Valve Failures and Dearadation a. Insoection Scooe During 1995, the licensee experienced failures and discovered degradation of important safety-related motor-operated valves Enclosure 2
. .
__- - .
. - . - _ . -_ - . - -
- I e
i
i (MOVs). Particular examples involving the licensee's Low Pressure
J Coolant Injection (LPCI) inboard injection valves were addressed by NRC inspection reports 95-17. 95-19. and 95-25. The current
- inspection reviewed subsequent licensee records to determine
- whether there was evidence of any adverse trends in MOV
-
performance. The records reviewed covered the period since
'
,
approximately the end of 1995.
- In this inspection. NRC inspectors specifically reviewed the
- maintenance records and surveillance test results for the LPCI inboard injection valves that experienced problems during 1995 (1/2E11F015A and B). Additionally MOV degradation and failures recorded on Deficiency Cards. Significant Occurrence Reports 4 (SORS), and MOV Testing and Tending Sheets were reviewed l generally, and the more significant examples were reviewed in
- detail. These significant examples were as follows
'
tracking Description Number C09601124 The breakers for RHR shutdown cooling isolation valve
'
(3/19/96) 1E11F006B and several other MOVs were found tripped during the outage. This was apparently caused by accidental bumping of the breakers during work activities. .
i Modifications to make the breakers less susceptible to "
such accidental trips were under evaluation.
C09601767 Plant service water to turbine isolation valve 1P41F310D (4/13/96) tripped on thermal overload when cycled three times in rapid succession. The correct size overload device had not been installed and the device had not been jumpered out as intended by a modification that had been performed in the previous outage (presumably in 1994). The licensee's corrective actions for the deficient installation included hardware corrections for 1P41F310D and its sister valves, documentation corrections. and training of design and installation planning personnel.
C09601946 The RHR service water to RHR crosstie valve 2E11F073A (4/18/96) would not stroke as a result of excessive actuator worm gear wear. The gear was replaced and a change to the operating procedure was requested to reduce operating forces. Inspection of like valves was specified. ]
Enclosure 2
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. _
,
a l
,
. Tracking Description
- Number
C09603349 The RHR service water system cross-tie valve 2E11F119A (7/7/96) would not open electrically. Also, the open limit switch was not set correctly. This was the result of a 3artial
- torque switch roll pin failure. The torque switc1 was
- replaced with a heavy duty model and the limit switch was 1 correctly set. Additional evaluation was specified, including a diagnostic test.
C09602837 The RCIC torus outboard suction valve 2E51F029A would not- ,
(5/29/96) close electrically but would open. The apparent cause was !
dirty torque switch contacts and the valve operated satisfactorily after the contacts were cleaned. A change' l to the periodic maintenance procedure was initiated to !
assure cleaning of the contacts. l C09603418 The plant service water isolation valve IP41F420A would (7/12/96) not electrically close. The valve had not returned to 1 electrical from manual operation due to the actuator tripper fingers being out of adjustment. ,
b. Observations and Findinas ,
LPCI inboard injection valve non-routine maintenance was found to have consisted largely of activities to address industry issues '
and to assure against problems previously experienced at Hatch.
Examples included drilling of holes to preclude pressure locking and inspections of stem couplings for proper installation. There were no failures reported during the period and the only significant corrective maintenance noted was the replacement of worn actuator worm shaft bearings on valve 1E11F015B. The licensee experienced the failure of a newly installed torque switch on valve 1E11F015A prior placing it in service. The failed torque switch was a heavy duty model intended to preclude the likelihood of a future roll pin failure. The failure was due to a loose face plate and was detected in a dynamic diagnostic test.
The LPCI inboard injection valves performed satisfactorily in the surveillance tests.
The inspectors' general review of MOV failures and degradation did not identify any adverse trends. For the significant MOV problems that were reviewed in detail (above table), the associated valves were found to either not have an active safety function or the active safety function was not adversely impacted. From their review of these examples, the inspectors found that the licensee *s evaluations. cause determinations, and the corrective actions Enclosure 2
i
specified were satisfactorily. In several cases, the corrective actions reviewed were not complete and the associated nonconformance document remained open.
The MOV problem identified as tracking number C09601767 (see table above) was of particular concern to the inspectors because it involved deficient engineering planning for a modification, resulting in a failure to install important design features.
These features were a larger size thermal overload protective device than originally installed and a jumper to preclude the overload protection from functioning during normal operation.
Although not detected until the 1996 Unit 1 outage, this modification had been developed for and installed during a 1994 outage. The inspectors' review of the SOR, which documented the item, found that the root causes were determined, the extent of condition was evaluated and found limited to the one modification, and apprcpriate corrective actions for the hardware condition and causes were specified.
c. Conclusions There was no evidence of adverse trends in MOV failures or degradation during 1996. Significant problems such as the LPCI inboard injection valve failures that occurred in 1995 were not in i evidence. Overall,.the licensee's MOV program appeared to be maintaining the important Hatch MOVs in satisfactory condition.
One licensee identified MOV 3roblem, involving improper modification of MOV 1P41F310), was of concern in that it reflected negatively on the licensee's engineering planning for a modification. The deficient planning resulted in failure to install the overload protection intended. This concern reflected negatively on the licensee's engineering, rather than maintenance.
III. Enaineerina El Conduct of Engineering On-site engineering activities were reviewed to determine their effectiveness in preventing, identifying, and resolving safety issues, events, and problems.
El.1 General Comments (92903)
l a. Insoection Scoce i The inspectors reviewed a completed MWO 2-96-2764, Change Molded Case Circuit Breaker (MCCB) Tri) Settings, and observed engineering activities during t1e RCIC outage (paragraph M1.3).
Enclosure 2
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l
b. Observations and Findinas The inspectors documented in irs 321.366/96-06. -07, and -10 observations involving the changing of MCCB trip settings. The inspectors observed from the review that the MWO craft
<
instructions were the same as documented in the previous irs.
These included engineering oversight and the required functional testing following adjustments. The review indicated that the instructions were followed and functional testing was performed.
c. Conclusions The inspectors concluded that the adjustments to the MCCBs are being performed in accordance with approved instructions. ;
E1.2 Enaineerina Review of PSW Air Release Valve Leak a. Insoection Scone (37551)
The inspectors monitored the licensee's analysis and evaluation of a pin hole leak in the body of PSW pump discharge air release valve 2P41-F332D.
b. Observations and Findinas l
The inspectors monitored the licensee's activities associated with !
l a pin hole leak discovered in the body of PSW air release valve '
2P41-F3320. The leak was discovered on September 25 by maintenance Jersonnel who observed a rust stain on the body of the valve. Furtier investigation of the rust stain indicated that a very small through-wall leak had developed. The licensee took the
,
appropriate actions required by TRM Specification T 3.4.2 for structural integrity of ASME Code Class 3 components. ,
An evaluation of ultra-sonic test (UT) data by the licensee indicated that there was no wall thinning in the area of the leak.
A licensee review of radiographs from an RT of the leakage area showed an indication consistent with casting shrinkage. The casting shrinkage crack was branched and irregular in shape and was contained within an approximate area of one inch in diameter.
The licensee concluded that the through-wall flaw has probably been on the valve since its installation.
An operability assessment of toe valve by the licensee indicated that the valve is capable of performing its intended function during normal operation, transients, and design basis accidents.
The licensee submitted a letter to the NRC dated October 4 requesting temporary relief from ASME Code requirements until the next outage of sufficient duration. As a compensatory action, the
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>
Enclosure 2
!
l
licensee made a commitment in the letter to visually inspect the valve daily to ensure the leakage does not change significantly.
The inspectors reviewed the outside rounds log and verified that a visual inspection of the valve was documented. The documentation indicated that the valve was inspected once per shift commencing on October 5.
c. Conclusions The engineering evaluation and analysis for the small leak in PSW ,
air release valve 2P41-F332D was reasonable and timely. The j appropriate actions as required by the TRM specification for i structural integrity were taken. The compensatory actions for the small PSW through-wall air release valve leak were reasonable.
E2 Engineering Support of Facilities and Equipment E2.1 Reactor Protective System MG Set Trio (Unit 1)
a. Insoection Scooe (92903)
On October 8. an ESF Actuation occurred on Unit 1 following a trip l of the 1B Reactor Protective System (RPS) Motor Generator (MG)
set. The trip was simultaneous with a ground on the safety-related 1D 600 volt bus.
.
b. Observation and Findinos The inspectors documented in previous inspection reports (IR),
>
such as IR 321.366/96-10. 95-22. and 95-18. the on- going difficulties with the type RMS-9 electrical circuit breaker trip devices. The licensee documented in Licensee Event Report (LER)
50-321/95-05, an occurrence involving a ground on the ID 600 volt bus and a trip of the 1B RPS MG set. These devices are susceptible to spurious trips due to grounds.
l The inspectors were informed that the most probable cause for the trip was a ground on the 1D 600 volt bus. This ground caused the RMS-9 do" ice on the supply breaker to the IB MG set to actuate.
Onsite engineering personnel had portable instrumentation installed on the 10 bus. The results indicated that very short duration grounds were being detected as often as five times an hour. The durations were so short that the operators were unable to observe them on the ground detection lights. Starting during the first week of October, long duration grounds with low impedance began to be detected.
The inspectors were also informed that data indicated that the actuation of a RMS-9 trip device, due to a ground, appeared to be both time and magnitude dependent. A short duration ground, with Enclosure 2
-
high impedance, would not affect the devices. However, a long duration ground, with low impedance, would affect the devices and cause circuit breakers to spuriously trip.
Licensee 3ersonnel continued troubleshooting activities and located tie ground, a heating element in a Cardox refrigeration unit. Repairs were made and both the short duration and the long duration grounds were no longer detected.
Conclusions The inspectors concluded that licensee engineering personnel vigorously pursued and corrected the grounding condition in a timely manner. The inspectors also concluded that, with the type RMS-9 devices currently installed in various electrical boards, that spurious circuit breaker trips due to long duration grounds with low impedance will continue to occur.
E2.2 Wirina Confiauration in Control Panels a. Insoection Scooe (37551)
The inspectors observed and were informed that the as-built wiring in various panels may not be accurately reflected on electrical I connection drawings, b. Observation and Findinas The inspectors reviewed the operating logs for September 20, 1996, and observed entries which stated, in part, the following, "While engineering and maintenance electricians were trouble shooting the indication lights on the 1G torus to drywell vacuum breaker the power sup)1y links were opened, the indicating lights did not extinguis1, but the lights for the 1H vacuum breaker did "
The inspectors were informed that wiring deficiencies were also observed by onsite engineering personnel when reviewing the electrical connection drawings for a CR alarm associated with a safety-related electrical board. The inspectors observed onsite engineering personnel checking and verifying the electrical wiring associated with the RCIC system, in the Remote Shutdown Panel (RSDP), using the electrical connection drawings. The phrase used by the licensee for this type of problem and activity was " red lining" The inspectors discussed this item with licensee management and were informed that the extent of the red lining problem was not known at the end of the report period.
The inspectors found that some of these deficiencies involved Enclosure 2
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!
l systems important to safety, such as RCIC, vacuum breakers, and ;
electrical board 1 alarms. '
c. Conclusions i
The inspectors concluded that onsite engineering was aware of the red lining problems and were in the process of correcting them. i At the end of the report period, the licensee had not provided the inspectors with information defining the extent of the identified red-lining problems and the method to address red lining problems that may be discovered in the future. This item is identified as an inspector follow up item. IFI 321,366/96-13-06. Additional Review of Wiring Deficiencies on Electrical Connection Drawings.
E2.3 Temocrary Modifications a. Insoection Scone (37550)
The inspectors reviewed the design controls associated with Temporary Modifications (TMs) to determine if this activity was consistent with regulatory guidance, Regulatory Guide 1.64 and ANSI N45.2.11-1974. Quality Assurance Requirements for the Design of Nuclear Power Plants, and the licensee implementing procedure 40AC-ENG-018-05 Temporary Modifications. Rev. 3.
b. Observations and Findinas The licensee maintained a relatively low number of active TMs:
twelve on Unit 1 and six on Unit 2. The age of TMs was limited to less than one refueling outage. Periodic reviews of TMs were performed as required by the licensee's procedure, and management approval was required for the extension of the estabnshed completion date. The design control requirements of ANSI N45.2.11-1974 were appropriately implemented in the installed TMs.
In general, the 50 59 safety evaluations were adequately justified and documented. The exception was identified by the licensee in June 1996, in which the 50.59 initial screening did not identify that a main steam relief valve tailpipe alarm setpoint was included in the FSAR thereby recuiring a full 50.59 evaluation.
The evaluation was performed in June. 1996, and determined that no unresolved safety question was involved with the tem)orary alarm setpoint change. The licensee adequately resolved t1is minor deficiency.
c. Conclusion Design controls for temporary modifications were good, as demonstrated by the low number and limited age of TMs. Regulatory requirements for design controls were adequately implemented.
Enclosure 2
- .- _ _ . _ _ _ _ _ . . _ _
_ _ _ _ _ _ _ _ _ . _ _ _ _ . ~ . _ . __
E2.4 Desian Chances and Plant Modifications
, a. Insoection Scooe (37550)
l The inspectors reviewed the adequacy of design changes and walked down one of them in order to inspect the implementation of modifications in the field.
b. Observations and Findinog
, The inspectors reviewed two Minor Design Changes (MDC) and two l Design Change Requests (DCR) as listed below:
, MEC 94-5071: Replacing Snubbers with Sway Struts i MDC 95-5003: Addition of Stiffeners to
! Chillers 1 Z41-B008A. B. C l
DCR 94-016: Removal of Snubber 2B21-MSRV-R62 DCR 96-024: GE RMS-9 Breaker Trip _ Unit Replacement i
l MDCs were generated by the engineers on site for minor modifications. DCRs were generated per Request of Engineering Assistance (REA) from the site for complicated engineering analyses and were performed by Southern Company Services (SCS) in Birmingham. Alabama.
The inspectors reviewed the theory and assumptions for the modifications and the 10 CFR 50.59 Safety Evaluation for the l changes and determined that they were adequately reviewed and
'
evaluated. No unreviewed safety concerns were found. A review of l DCR 96-024 was performed to confirm that appropriate electro-magnetic interference (EMI) testing had been specified.
l The modifications for MDC 94-5071 and DCR 94-016 were already com)leted. The inspectors randomly selected MDC 94-5071 for a wal(down inspection to verify the comaletion of the modification.
i The MDC 94-5071 replaced snubbers wit 1 sway struts on su) ports 2E11-RHR-R224, 2E11-RHR-R228, 2E11-RHR-H714 and 2E11-RH1-H715.
l The purpose of this modification was to reduce the maintenance 1 cost for the snubbers and outage time. The licensee's engineers reviewed the stress analysis which indicated that there was very little thermal movement at these hangers. Therefore, adequate rigid struts could be sized to carry the faulted loads that the snubbers were originally designed to carry while allowing thermal growth. This means that the snubbers could be replaced with the sway struts because of very little thermal movement. The inspectors verified the size of sway struts in the field, compared
, them with the applicable drawings, and verified the capacity of
- sway struts through the certificate of purchase receiving. The j inspectors determined that the modification of the supports was
! adequate.
!
j Enclosure 2
. - . .
c. Conclusions The inspectors concluded that the design changes and plant modifications were adequate.
E2.5 RHRSW Heat Exchanaer 1B - Possible leak a. Insoection ScoDe (92903)
The inspectors observed and reviewed the various licensee activities involved with a possible leak in the Residual Heat Removal Service Water (RHRSW) heat exchanger 1B.
b. Observation and Findinas Starting in August,1996, the inspectors were informed that chemical sampling indicated the presence of suppression chamber water in the service water side of the IB RHRSW heat exchanger.
This data indicated a possible leak in the heat exchanger. In it's standby configuration the tube side, containing service water from the river, is at atmospheric pressure. In this same condition, the RHR water on the shell side is pressurized to a3 proximately 60 psig by the RHR/ Core Spray (CS) keep-fill system.
T1e keep-fill system uses jockey aumps to pressurize the RHR/CS systems with pump suction from t1e water in the suppression chamber.
The inspectors observed and reviewed the activities associated with this potential leak. This included review of on-going data, review of licensee supplied information, attendance at meetings called to discuss this item, and discussions with various licensee personnel.
The inspectors found from the reviews. meetings and discussions the following:
-
The total activity was approximately 1.00 to 2.00 E-06 gci/ml and decreased by a factor of ten when the system was operated on August 23.
-
Three days after operating the system the activity returned to approximately the pre-operating levels and remained at this level .
-
On September 26. the system was placed in operation for a period of six days after the system was drained and flushed.
-
Ten days after the six day system operation and following a short duration operation the total activity increased by a Enclosure 2
_ _ _ _ . _ _ . _ . _ _ _ _ _ . _ _ . _ _ _ _ _ . _ .
factor of ten to 1.00 E-05 uci/ml.
The inspectors were also informed that the radioactive isotopes, such as cobalt 60 and cesium 137, as well as zinc contained in the samples. corresponded to those in the water of the suppression.
chamber.
Onsite engineering was tasked with evaluating the )ossible leak.
The inspectors were informed that the possible leac appeared to be very small and the rate was approximately one drop every four seconds. The inspectors observed from information supplied by licensee technical personnel the following:
-
A question was raised concerning the structural integrity requirements of the Unit 1 RHRSW heat exchanger if there is an internal tube leak.
-
The only ASME Section XI reference to heat exchanger tubes is in the Pressure Testing section. Hatch is committed to the 1989 ASME Section XI Subsection IWA - 4'/00 which states, in part. " exempted from the system hydrostatic tests...(2) heat exchanger tube plugging." and "(6) tube-to-tubesheet repair l welds." There are no other references to heat exchanger tubes.
-
The ASME Section XI code does have requirements for the l external shell, the nozzle-to-shell welds, and the tube sheet-to-shell weld. l
-
The TRM T 3.4.2. Structural Integrity LCO. is applicable for :
the RHRSW heat exchanger and if there was an external leak of the heat exchanger _ or of a nozzle-to-shell weld. TRM T 3.4.2 Conditions A and B would be entered.
l
-
Since there are no ASnE Section XI requirements directly addressing tube leaks the Structural Integrity LC0 does not ;
apply.
-
The fabrication of the heat exchanger is such that a shell to tubesheet leak would be an external leak.
The inspectors also reviewed NRC documentation and discussed this item with NRC personnel. Portions of the documents reviewed were:
10 CFR 50.55a. Codes and Standards Paragraph (g)(4) and various documents that discussed the applicability of the ASME code.
The inspectors found from these observations, reviews and discussions that the licensee was following the applicable section of the TRM.
Enclosure 2
'
c. Conclusions The inspectors concluded that there is a possibility of a tube leak in the IB RHRSW heat exchanger. The inspectors also concluded that the licensee technical aersonnel are performing a ;
good job of monitoring and assessing t11s issue.
E4. Engineering Staff Knowledge and Performance E4.1 Resolution of Eauioment Problems i
a. Insoection Scooe (37550)
!
The inspectors reviewed the licensee's activities for '
identification and resolution of equipment operating problems to determine if these actions were consistent with the 10 CFR 50 Appendix B requirements.
l b. Observations and Findinas l The inspectors observed an equipment reliability meeting conducted on September 17, 1996 and noted good inter-organizational involvement in the identification and monitoring of equipment reliability issues. The participants included representatives from engineering. maintenance and operations. There were 59 items on the reliability tracking list, twelve were designated as top reliability problems. In January 1996, there were 116 items on the tracking list. Responsible engineers presented status information on several of the top reliability problem items, The periodic reliability meetings provided an example of good engineering focus on operations issues.
The inspectors reviewed several examples of equi) ment reliability 3roblems addressed by engineering. The mairi tur)ine electro-lydraulic control (EHC) system and the Reactor Protection System Motor Generator (RPS MG) sets were examples of effective problem resolution. EHC hydraulic fluid degradation caused clogged valve servo-filters which resulted in several plant transients since 1992. As a result of the identification and elimination of contributors to this fluid degradation. servo-filter clogging has been resolved. A history of RPS MG set tripping was ended with design changes to the MG set control circuit and MG set room ventilation to improve ambient temperature control.
The inspectors noted one example of ineffective resolution of an equipment problem related to the Unit 1 Reactor Feed Pump (RFP)
mini-flow valves which caused power transients in 1995 and 1996.
The valves opened too fast. resulting in a reactor level transient and subsequent recirculation pump run back. After the August 1995 Enclosure 2
_ ___ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ . _.
transient, the valve operating time was adjusted and a design change modified the valve. A similar transient occurred in August 1996.-demonstrating that the corrective actions'were not effective. An event review team (ERT) was initiated after the !
1996 event; however, the report was not yet complete.
-The inspectors examined the issue of main transformer fan grounds that have caused spurious trip)ing of 600 VAC breakers with GE RMS-9 digital trip devices. T1is is a recurring equipment problem that has resulted in power reductions and a trip of Unit 1 in 1993. The transformer fan grounds are inducing electrical noise on the 600 VAC bus which results in the tripaing of bus supply breakers other than the supply breaker for tie grounded fan motor.
The 600 VAC breakers are equipped with GE RMS-9 trip units that are sensitive to electromagnetic interference. This spurious tripping of GE RMS-9 trip devices is an industry problem that was identified by the NRC in Information Notice 93-75.
The most recent transformer fan motor grounds which resulted in spurious trips occurred on July 25 and August 1.1996. These two events resulted in trips of breakers that had been retrofitted by the licensee with noise filter kits. The noise filter kits were ,
found to be effective for some but not all ranges of electrical !
noise that can be induced on the 600 VAC bus. !
A management meeting in August 1996, examined the recent main transformer cooling fan failures including the failure of one of the 16 new replacement motors. The licensee concluded that the failure rate for the transformer fans was normal and that modifications to further reduce failures were not justified.
Management decided at the meeting to continue to follow industry developments on EMI causing spurious trips and to implement DCR 96-024. This DCR will replace six GE RMS-9 trip devices on Unit 1 breakers which have experienced spurious trips in the past.
Trip devices from two different manufacturers were being installed to gain experience as a possible widespread replacement of RMS-9 devices. The replacement trip devices will be GE and Westinghouse microprocessor based trip units that have been tested using the latest industry guidance for EMI. The new tri) devices will be installed on six spare breakers and the spare )reakers will be installed as replacements for breakers on non-safety 600 VAC switchgear busses 1A and 18. There will be three each Westinghouse and GE trip devices installed, with two of each type being installed on 600 VAC Bus 1B and one of each type being installed on 600 VAC Bus 1A.
Enclosure 2
- - _- -- --- - _ = _ _ _ . _ . _ _ ._
4 c. Conclusion Engineering activity for identification and monitoring of equipment reliability demonstrated a good focus on operations issues. Periodic equipment reliability meetings provided a mechanism for inter-organizational involvement on equipment problems. Although examples of ineffective corrective action were
-
noted, several exam equipment problems.ples demonstrated The ins)ectors effective concluded that the resolution licensee'sof plant 31anned actions to resolve tie spurious tripping of 600 VAC 3reakers were reasonable and prudent.
E4.2 Disoosition of Deficiency Reoorts a. Insoection Scoce (37550)
~
The inspectors reviewed the disposition and corrective actions on deficiency reports to determine if they were adequately reviewed.
,
evaluated, dispositioned, and corrected.
b. Observations and Findinas i
The inspectors reviewed five deficiency reports as listed below.
The deficiencies were classified as Significant Occurrence Reports (SOR).
Reoort No. Condition
- C09601051 An electrical panel was dropped during lifting C09601396 Six slings were found in use without a load test mark C09602117 Leak at a socket connection weld in a pipe
C09602172 Wrong welding material and procedure used i C09602831 Welding Inspector not Certified All of the above deficiency reports were classified as significant, but not reportable. The inspectors reviewed the root
'
cause analyses, evaluation and corrective actions and discussed them with the assigned engineers. The corrective actions included
, the retraining of employees. issuing memos, revising procedures, performing analyses, and implementing modifications in order to correct the problems or prevent recurrence.
l c. Conclusions
^
The inspectors concluded that the licensee engineers performed an
,
'
adequate disposition on the deficiency reports. The licensee also took the required corrective actions to fix the problem or prevent recurrence.
, Enclosure 2
.
b
!.
!
! 1 3 36 i
E6. Enoineerino Oroanization and Administration
- E6.1 Contractor Oversicht
a. Insoection Scooe (37750)
- The inspectors reviewed the licensee's actions to address
- contractor control 3roblems to determine if corrective actions j were consistent wit 1 the 10 CFR 50 Appendix B requirements.
b. Observations and Conclusions l
3 The Plant Modifications and Maintenance Su) port (PMMS) engineering j organization was administratively responsi)le for contractor
- oversight. Early in 1995, two high profile events in the spent i fuel pool were the result of contractor errors. The licensee's
'
deficiency reporting system and a Contractor Control audit in May 1996, identified additional cor, tractor errors in the previous two
- years. Contractor oversight was included in the Plant Major i Problems List. The licensee routinely uses contractor support for i craft activities during outages. The evaluations of this problem indicated that procedure compliance and failure to impose licensee
- quality standards were contributors to this problem. The i complexity of procedures and inadequate oversight were additional j factors.
j The licensee was developing corrective actions to address the i contributing factors to the contractor errors. These included i simplifying craft procedures, improved contractor training, and
- increased oversight. Discussions with the licensee indicated that j contractor performance would be monitored over the next two refueling outages to assess the effectiveness of implemented
- corrective actions.
c. Conclusion
- The licensee had identified contractor oversight as a major plant i
'
problem and was developing corrective actions to improve contractor performance. This had been previously identified as an ,
engineering performance area needing improvement. !
!
E6.2 Enaineerina Backloa a. Insoection Scooe (37550)
The inspectors reviewed the backlog of open DCRs and MDCs.
Enclosure 2
_____ __ . _ - _ _ _ _.. _ _ __ _ . . __ __
4
) b. Observations and Findinos
'
The licensee's DCR and MDC Status Report dated September 3. 1996, showed a backlog of approximately 124 open Design Change Requests ar.d 121 open Minor Design Change Requests. The total backlog of o)en DCRs and MDCs has continued on a positive trend downward.
'
T1e backlog of DCRs has steadily declined since 1993 after formation of the Change Control Board, from a high of 563 to the current level of 124. The licensee began implementing MDCs in 1993, with an overall total of 269 MDCs being initiated since that time with 121 open at present.
c. Conclusion ,
l The licensee has been effective in reducing and managing the backlog of design changes.
E7 Ouality Assurance in Enoineerina Activities - Self Assessment a. Insoection Scoce (37550)
! The inspectors reviewed assessments of onsite engineering and
,
technical support activities.
a
- b. Observations and Findinas On-site engineering and technical support consists of the
'
Engineering Support (ES) organization. Plant Modifications and Maintenance Support engineering organization, and maintenance
, performance team engineering. Assessments of engineering performance were performed through routine Quality Assurance e audits of engineering programs and activities, informal quality
checks. and other formal assessments (e.g. reactivity assessment, a
special audits, third party assessments, and other reviews conducted in preparation for independent external assessments).
. The inspectors reviewed the most recent audits performed of
engineering performance conducted in the areas of Engineering and Technical Support Programs. Design Change Requests, non-licensed training. Minor Design Changes. Contractor Controls. Corrective
- Action Program. Special Processes. Rigging. Radiography Controls.
and Inspection and Inservice Testing Program. The audits resulted
- in some audit findings and comments being identified. For example. the audit of Contractor Controls identified four audit i findings and one comment. The audits were found to be well planned and documented. The inspectors noted that audit findings were appropriately evaluated by the responsible organization and corrective actions were tracked to resolution. Based on an interview with the ES Manager, each supervisor in the Engineering Support department performs at least 1 Quality Check per month and once each week the manager presents the results of a quality check
, Enclosure 2
_
._. _ _ _ _ . _ _ . . . _ . _ . _ _ _ - _ . . _ _ _ - _ _ _ . _ - . _ _ _ . - - . - -
-
!
!
!'
t at the morning meeting. The inspectors reviewed a sample of the past cuality checks and found that some of the quality checks proviced good assessments of engineering performance and some did ;
not involve Engineering performance at all. Compliance issues identified during the quality check were documented by a j deficiency card for tracking and corrective action. i c. Conclusion !
!
The inspectors concluded that assessments and audits of i engineering activities were effective in identifying and assuring '
correction of deficiencies in engineering performance.
'
l E8 Miscellaneous Engineering Issues (92700) (92903) I
!
E8.1 (Closed) IFI 50-321.366/96-11-01: Review of Engineering l Evaluation on the Effects of Harmonics on EDG Operation. '
a. Scooe of Review (92903)
The grid harmonics were documented in IR 50-321.366/96-06. The inspectors reviewed an onsite engineering evaluation involving the grid harmonics.
b. Findinos and Observations The evaluation stated the problem, contained investigation results and recommendations. The problem was stated in part as follows:
-
Reverse power trips are occasionally being experienced on the EDGs during testing and occurs on both units.
-
Reverse power trips can only occur while an EDG is paralleled to the grid.
-
During recovery from a LOSP the operator wiIl need to operate the EDGs in parallel with the grid.
_
Misoperation of equipment in general is significant because it
. tends to reduce operator confidence in their own ability and in I the reliability of the equipment.
l l The inspectors observed that the results of the investigation i indicated that misoperation of equipment was evident in at least i two of the events reviewed. In these cases operators observing
'
I
,
the wrong meter and manipulating the wrong switch was involved. ;
i The evaluation results stated the following: There appear to be -!
two major factors contributing to these human errors. First.
l there is some degree of stress imposed on the operators when j performing this task owing to the need (real or perceived) to take J
Enclosure 2
,
c .
m - - - - ,. -- ,-y . -. , - - - . - - - - - . -
__.
actions quickly in order to successfully perform the test and avoid ecuipment damage. So much so that many operators employ a two-hanc method, operating two switches almost simultaneously.
Secondly under pressure to perform rapidly and precisely, the correct control switch and indication can be difficult to find amid similar devices.
The evaluation results discussed the design of the reverse )ower relay and stated that the actuation of these relays are bot 1 magnitude and time dependent. The relays receive their current input from phase 2. The evaluation further stated that with an l EDG operating at low load and tied to the grid, the harmonic was j present on phase 2 and showed a very high total harmonic -
distortion of approximately 40%. Under these conditions data traces showed significantly less current on phase 2 as compared to the other two phases. With this anomalous current behavior, it is possible to receive a reverse power trip even when an EDG is supplying power to the grid at low power output levels. The cause ,
of this current anomaly is unknown. !
The evaluation commented that the Plant Hatch design did not allow for voltage control from the MCR when the voltage regulators are in the automatic mode. Adjustments in automatic are performed in the EDG rooms at the local control panels. This also makes it i difficult to parallel with the grid because it is done in manual mode from the MCR. ;
The evaluation contained 10 specific recommendations. Among these l were the following:
-
The connection for the reverse power relays should be changed from phase 2 to another phase.
-
The time delay on the reverse power relays should be changed from 5 to the maximum value allowed. j
-
Procedures involving parallel operation with the grid should be revised so as to remove unnecessary limits. restrictions and urgency of actions.
-
An additional meter should be installed on the Unit 1 control board so that KW and KVAR can be read at the same time. !
-
The KW meter cover (zebo) and EDG speed switch should be painted a unique color for ease of identification. ,
Additional recommendations involved training and observations by management. One item that was verbally discussed concerned the EDG governor droop setting. The current setting is 50 and this would be raised to a setting of 100, the maximum. With a higher Enclosure 2
,
_. ._._ _ _ _ . - . _ . _ _ _ _ _ _ _ _ - _ _ . _ _
'
]
40 ;
setting, the EDGs would be less' responsive to grid fluctuations.
- c. Conclusions The inspectors concluded that the evaluation discussed the )
l technical issues.adecuately, was very through, and made !
j recommendations basec on sound engineering judgement.
i E8.2 (Closed) VIO 50-321/96-04-03: Inadequate Procedure for 0perating
- the Reactor Core Isolation Cooling (RCIC) system from the Remote
{; Shutdown Panel (RSDP).
.
This violation was identified when licensee personnel attempted to l operate the RCIC system from the RSDP and were unsuccessful. The
<
inspectors observed the attempt and concluded that the procedure l was technically inadequate.
i The inspectors reviewed the response, dated May 21, 1996, and
, observed that personnel error was stated as the cause for the violation. The response indicated that the error was involved
'
- with a design change, which was implemented in May 1993. The j design change installed a control switch on the RSDP which was i' used to open valve IE51-F119. Steam to Turbine Bypass. The response stated that modifications and Operations personnel i responsible for identifying procedures affected by design changes
! failed to identify the RSDP procedure 31RS-0PS-001-1S. Shutdown l From Outside the Control Room, as requiring revision. The
- res)onse also stated that implementation of Design Change Request
. (DCR)94-033 has since removed valve 1E51-F119. Based on the
!
reviews by the inspectors and the actions taken by the licensee this violation is closed.
! E8.3 (Closed) LER 50-321/96-03: Component Failure Results in Unplanned i Engineering Safety Feature System Actuation.
! This problem was discussed in IR 50-321.366/96-04. No new issues were revealed by the LER.
E8.4 (Closed) IFI 50-321.366/96-06-09: Review of DCR Work Deficiencies l and Licensee Corrective Actions.
.
l This item was identified to review the licensee *s root cause
! evaluation and corrective action for the relay wiring errors that
- were noted during DCR work on Unit 1. The licensee has determined the causes for the relay wiring errors and identified corrective ;
actions that will be taken to prevent similar relay wiring !
problems The inspector verified that 3 of the 4 required i j corrective actions had been completed. The fourth item is ;
- scheduled to be completed prior to the Unit 2. 1997 Outage. Based l
,
( on the information reviewed this item is closed. !
l Enclosure 2 i
!
l ,
. _ _ _
.. ._ . _ _ . . ~ J
. .- . - - - . . . . . . . . . . _ - - - . - . - . _ - - . . - _ . . . _. . _ - - _ - - -
, I i
"
i
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l
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! E8.5 (Closed) IFI 50-321.366/95-27-01: Electro-Hydraulic Control (EHC)
- System Problems !
.
i This item addressed a recurring problem with clogged EHC system !
- valve servo-filters which resulted in several plant transients i since 1992. Following the reactor scram in January 1996, the i i licensee initiated'an Event Review Team (ERT) to evaluate the ;
- causes of the clogged filters. The IFI was identified to track !
j the problem evaluation and long term corrective actions.
-
The ERT determined the contributors to the hydraulic fluid degradation which resulted in the formation of a sludge buildu)
! and clogged servo-filters and initiated corrective actions. T1ese actions included a system chemical flush, system filter material
change, and periodic dehydration. Subsequent periodic inspection l of the Unit 1 servo-filters identified no sludge build-up and no i filter clogging. This indicated that the problem had been
! corrected on Unit 1. Remaining Unit 2 action included a system chemical flush, planned for the next refueling outage.
. E8.6 (Closed) URI 321/96-02-01: Emergency Diesel Generator (EDG)
g Procurement ANSI Standard Issues i
.
This item addressed an apparent deficiency in the procurement i specification of the replacement EDGs in that the specification did not list all applicable industry standards referenced in the
'
-
Final Safety Analysis Report (FSAR) for the EDGs. The concern was i that the vendor's Quality Assurance Program did not meet the
! regulatory requirements for the manufacture of safety-related
)
'
equipment. The item was unresolved pending further NRC review.
This review determined that the EDG vendor 10 CFR 50 A)pendix B
-
program had been previously reviewed and approved by tie NRC.
) E8.7 (Closed) IFI 50-321.366/95-02-05: Scope of Valves and Testing.
This IFI identified concern as to the scope of MOVs and design functions included in the Hatch GL 89-10 3rogram. The NRC Office i of Nuclear Reactor Regulation evaluated tie MOVs and functions
'
which the licensee had deleted from their GL 89-10 program, as ,
well as the bases for these deletions. The results of the ;
evaluation were provided to the licensee in a Safety Evaluation '
Report dated October 16, 1995. This report rejected the j
licensee's deletion of over 50 MOVs from the Hatch GL 89-10 i program.
During the current inspection, the inspectors questioned licensee !
- personnel on their resolution actions for this issue. In
response, the inspectors were informed that the previously deleted MOVs were being returned to the Hatch GL 89-10 MOV program
,
consistent with the results of the October 16, 1995 NRC safety
,
Enclosure 2 :
l
, - . . - -
-. . - - _ . . . _ . ,_ - --
- .. -. - _- ._ -_ - . . - . - - - - - - - - - - - - - _ - . - -
.
!
evaluation. The inspectors reviewed licensee correspondence from the Hatch Project Support organization initiating these changes (Correspondence Log Nos. HL-5155. dated April 29. 1996 and HL-5246. dated September 30. 1996) and verified that they specified the return of MOVs to the Hatch GL 89-10 program consistent with the NRC safety evaluation. Based on this action, the NRC inspectors- considered the issue resolved.
E8.8 (Closed) IFI 50-321.366/95-25-01: Valve Factor and Coefficient of Friction Issues.
This item involved three issues identified in the NRC review of
the licensee's GL 89-10 program:
(1) The valve factor (VF) used in calculating the settings for
,
'
valves 2B31F031A/B. 1B21F016 and 1B21F019 was not sufficiently justified.
(2) The valve stem coefficient of friction (C0F) established was not adequately justified.
,
(3) The licensee was in the process of addressing new industry l information regarding performance of valves that could experience blowdown conditions.
At the NRC's request the licensee provided a written response letter addressing these issues. This letter, dated January 26.
'
1996, proposed resolutions of the above issues as follows:
(1) Increased VFs were proposed. The bases for these VFs were described. The licensee also stated that industry l information regarding the VF design assumptions would continue to be monitored and that valves 2831F031A/B would be modified to provide limit switch control of closing.
(2) A C0F value of 0.18 was proposed for all non-torque tested valves and it was stated that a review of static and dynamic test data would be an ongoing effort to confirm the validity of the design assumptions.
(3) Sharp edges and improper internal clearances would be corrected on s)ecified valves in accordance with criteria from the EPRI 3erformance Prediction Program.
'
The licensee's proposal was determined to be acceptable to the NRC
- as stated in a letter from the NRC to the licensee dated February 29. 1996.
I In the current inspection, the inspectors verified that the i licensee had implemented the resolutions stated in their response.
I Enclosure 2 i
.
_ , , . _ .._. .
n _ _ . . _ . ,
.- . ... . -. _ - -
Verification was accomplished through a review of the following documentation:
(1) The licensee's current Torque Switch Setting Guide of VFs, Work Orders 29501968 and 29501969, modifying 2B31F031A/B for limit closing, and VF Calculation SMNH 95-031 for
. 2B31F031A/B.
(2) The licensee's current Torque Switch Setting Guide of C0Fs i and recent dynamic and static C0F results for eight valves tested during 1996.
(3) Gate and Globe Valve Corrective Maintenance Procedure, 52CM-MME-011-05. Rev. 10, incorporating radii using and clearance requirements for valve internals.
Based on the above, the inspectors concluded that the licensee had completed its stated resolution actions and that this item was
'
closed. However, the inspectors did note a concern that was
brought to the attention of the licensee. The licensee had
, determined its C0Fs from torque measured at torque switch trip,
+
whereas somewhat higher values may be obtained at seating.
Licensee personnel stated reasons why they were unable to obtain satisfactory data at seating. The inspectors noted that in future periodic testing the licensee should evaluate C0F at seating, where possible, in order to assure that the values obtained were )
appropriately conservative. I IV Plant Support R1 Radiological Protection and Chemistry Controls R1.1 General Comments (71750)
Using Inspection Procedure 71750. the ins)ectors conducted reviews of radiological controls and practices. Recent past problems with failed fuel in Unit 1 combined with minor steam leaks continue to s
contribute to a high level of noble gasses throughout the plant.
,
The current level of noble gasses has caused the health physics
,
department to commit resources to hand frisking personnel after they get whole body Personnel Contamination Monitor (PCM) alarms
as they attempt to exit from the RCA. The regularity with which this occurs may have lowered the sensitivity of health physics personnel to the possibility that personnel exiting the RCA may truly be contaminated. On September 19. 1996, an NRC inspector was released from the RCA after having alarmed a PCM and a subsequent hand survey by a health physics technician did not detect contamination. The HP technician assured the NRC inspector that the PCM alarm was due to gas. At the inspector's insistence, Enclosure 2
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44 l
he was surveyed further and his shirt was found to be contaminated i at a level of 12,000 dpm/100cm'. ;
The inspectors reviewed and discussed two on-going chemistry ;
. sampling and analysis activities. The first involved the evidence ;
of sup)ression chamber water in the service water side of the 1B :
RHRSW 1 eat exchanger, which could be indicative of a leak in the !
heat exchanger. Engineering analysis of the possible leak is i discussed in aaragraph E2.5. The second involved the increasing j readings on t1e Unit 1 drywell fission product monitor. High :
readings on this monitor are in some instances indicative of l system leakage into the drywell. In both instances, the chemistry )
group has been very responsive and kept plant management well :
informed of the latest results and their trends.
l R1.2 Imorocerly Controlled Radioactive Material a. Insoection Scooe (71750)
The inspectors reviewed the circumstances associated with the licensee's identifying that a routine monthly contamination survey of the scrap metal storage area conducted on October 9 found three ,
pieces of metal that were contaminated. i b. Observations and Findinas The inspectors * review of the information arovided by the licensee identified that the contaminated material lad been determined to be the two room cooler heat exchangers from the "B" Reactor Recirc i Pump Motor-Generator (MG) room in Unit 1. The licensee's l procedures require that before a component can be removed from the !
reactor building. it must be surveyed fm loose and fixed contamination. Based on the surveys. a component is either ,
released as clean or controlled as radioactive material. I The room coolers were replaced in the last outage that ended on l April 28 of this year. One of the coolers had been cut in half.
No loose contamination was found, but fixed contamination was
measured at 100.000 dpm/100 cm over most of the surface area of ;
the coolers. An item is considered contaminated
if the fixed '
contamination level exceeds 5000 dpm/100 cm , When the components were removed from the MG set room. they were initially surveyed i for loose contamination. No loose contamination was found. but a survey for fixed contamination could not be conducted because of high background radiation levels. The components were placed in the Unit I railroad airlock for interim storage. An unrelated '
i event prevented a timely survey and caused the components to remain in the airlock over a shift change. A misunderstanding on the part of maintenance personnel that surveys had been conducted and the components had been released led them to move the l Enclosure 2
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! com onents from the railroad airlock to the scrap yard on or about i
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Apr 1 12, 1996. !
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l After the contaminated pieces were discovered, the health physics ;
technician took the necessary action to secure the area around the
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coolers. Additionally, the gate to the scrap metal yard was
, secured with a lock controlled by the health physics department. ;
A complete survey of all metal in the yard was conducted and the '
licensee found one more piece of contaminated metal. This piece was determined to have been used as part of air ducting in a :
reactor water clean-up system room. It's size was ap3roximately '
30" square. A small area on this piece was found to 1 ave fixed contamination at a level of 6000 dpm/100 cm 2
. All contaminated l metal was wrapped and moved to a location suitable for storage of contaminated materials.
The scra) yard is located outside of the protected area, but {'
within tie owner controlled area and is not used to store radioactive material. It is located within a fenced area with a locked access gate. The licensee stated that, on occasion, metal from the scrap yard is sold to the public and that any metal sold as scrap is surveyed for contamination before it leaves the scrap yard. The licensee also stated that there have been no scrap sales from the yard since the contaminated pieces of metal had been stored there.
Although the apparent causes are different, there have been other instances when contaminated materials have been released into uncontrolled areas. NRC Inspection Report 50-321.366/95-01, issued on February 1, 1995. documented the release of contaminated scaffolding and wood from the radiological control area. This was identified by the licensee during a routine quality check. As determined by the licensee, this event was caused by improper operation of an automated material frisker. ,
l On February o routine quality check conducted by health
)hysics personnel identified that some tools stored outside of the RCA were contaminated. This is documented in NRC Inspection Report 50-321.366/95-04. ,
c. Conclusions Control of radioactive materials at Plant Hatch is governed by 60AC-HPX-007-0S Control of Radioactive Materials. Rev.3. ,
Step 8.1 states that equipment, parts. material and waste which i have fixed surface contamination levels exceeding 5000 dpm/100cm' 1 beta-gamma shall be controlled as radioactive material. The l failure to follow procedure 60AC-HPX-007-0S. is identified as l Violation 50-321.366/96-13-03. Failure To Follow Procedures -
Multiple Examples.
Enclosure 2
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- P1 Conduct of Emergency Preparedness (EP) Activities j
Pl.1 Observation of Emeroency PreDaredness Exercise j a. Insoection Scooe (82301)
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The licensee conducted an EP exercise on October 2. 1996. The exercise started with a fire in the 2G 4160 VAC switchgear
- (Section F1). The exercise scenario progressed from an Alert to a i Site Area Emergency.
b. Observations and Findinas
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{ The ins)ectors observed activities in the Technical Support Center !
! (TSC). Emergency 0)erating Facility (EOF). O
- Center (OSC) and t1e simulator control room.perations OffsiteSup) ort autlorities
, were observed in the EOF from the State of Georgia. (Department of I' Natural Resources. Dose Assessment Group). Jeff Davis County. :
Tatnall County, and Toombs County. The TSC and the EOF were i. staffed and activated within the time specified in Section H (Emergency Facilities and Equipment) of the Emergency Plan.
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The inspectors observed that cables placed on the floor within the
. EOF from junction boxes to the communication equipment had floor mats securely taped over them to minimize the trip hazard.
i The inspectors observed the activities in the TSC and OSC. The
, TSC manager remained cognizant of the plant status and equipment i availability, conducted periodic meetings with principal TSC
personnel to discuss priorities, made announcements for updating
. purposes, and exercised excellent command and control functions.
j The OSC continued to be noisy. with several groups engaged in ,
unrelated conversations and generally being inattentive to the
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exercise. A similar negative observation. involving command and .
]
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control in the OSC. was documented in IR 321.366/96-07.
e The scenario was written to require entry into a General Emergency 4 due to severe fuel damage and a radiological release in excess of
- allowed limits. However.'information generated during the
- scenario from dose assessment calculations and a PASS sample did
not provide sufficient evidence of core damage warranting entry 1 into a General Emergency. The Emergency Director (ED) made the J correct decisions based upon available information from the
,
scenario.
Previous scenario control problems were documented in IR t
50-321.366/95-15 and IR 50-321.366/96-07 for the EP exercises held 1 August 23, 1995 and May 22, 1996. respectively.
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c. Conclusions
The inspectors concluded that scenario control is an area that l continues to need improvement. Due to simulation and scenario control problems, the criteria for a General Emergency was never !
reached as intended by the scenario objective. Command and control for the exercise in the EOF and TSC was excellent.
Command and control in the OSC continues to be poor.
P3 EP Procedures and Documentation P3.1 Offsite Emeraency Notifications a. Insoection Scooe (71750)
The inspectors observed licensee notifications to State, local, l and Federal authorities for compliance with procedure 73EP-EIP-073-0S. Offsite Emergency Notifications. Revision 11.
b. Observations and Findinas On October 2. during the licensee's EP exercise, the inspectors observed that difficulties were encountered in making telephonic contact with the Georgia Emergency Management Agency (GEMA). This difficulty was due to problems with both the licensee's and GEMA's communication equipment. The inspectors monitored radio traffic in the simulator control room on at least a couple of occasions and observed that transmissions with the appropriate acknowledgements were performed as required by 73EP-EIP-073-0S.
The inspectors also observed that followup notifications to State and local authorities were periodically made.
The inspectors reviewed the Emergency Notification form used by the licensee for making notifications to local authorities. The initial notification of state and local authorities was conducted within 15 minutes of the declaration of an Alert. This notification was by facsimile due to initial telephone communications equipment problems.
The simulator control room SOS. who was the ED during the initial phase of the exercise attempted to call the NRC operations center to notify them of the EP exercise. The NRC number called was listed in the licensee's Emergency Call List and Emergency Facility Telephone Numbers. This call was made as part of the scenario to meet the one hour NRC notification required by 73EP-EIP-073-0S. Communication with the NRC Operations Center was not established. The ED indicated that during the initial attempt a sound was received that resembled that of a facsimile machine.
Subsequent attempts to call the NRC Operations Center resulted in a busy signal. The ED called the Site NRC Resident Office after Enclosure 2
being unable to contact the Operations Center. The inspectors called the single telephone number listed for the NRC Operations Center the following day and encountered no 3roblems. NRC Operations Center personnel indicated that t1ey were not aware of any problems. The inspectors also noted that a facsimile number similar to the voice tele) hone number (5151 versus 5100) was listed directly beneath t1e voice telephone number in the Emergency Call List and Emergency Facility Telephone Numbers.
c. Conclusion Communications and potential communication equipment malfunctions continue to present problems associated with offsite notifications during the EP exercises.
F1 Control of Fire Protection Activities F1.1 Ot;ervation of Fire Briaade Drill a. Inspection Scooe (64704)
The inspectors observed a Fire Brigade drill on October 2.1996, which was conducted in conjunction with an EP exercise. The drill involved the 2G 4160 VAC switchgear located in the EDG building.
b. Observations and Findinos ,
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The drill was preceded by both a plant wide fire alarm and a voice l announcement over the PA system. The inspectors observed the i following: j
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The brigade members properly utilized both protective clothing i and SCBA equipment.
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Entry into the west door of the 2G 4160 VAC room was performed ;
properly with adequately deployed hose lines. i
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The brigade utilized the fire fighting van which was equipped !
with information for the leader to use in developing fire i fighting strategies. One strategy was to go at the fire from the west through the outside door.
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The radios being used by the brigade members could not i communicate with the simulator control room. The brigade j leader had to use runners and the telephone system for communications. i
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The brigade arrived at the scene approximately 15 minutes after the alarm was sounded, the fire was considered under control Enclosure 2
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a) proximately five minutes later, and out five minutes after tlat.
The ins)ectors found that the brigade leader's directions were thoroug1 accurate, and effective during the fire fighting effort.
The inspectors also found that, by using the fire fighting van, sufficient equipment was brought to the scene to properly perform the fire fighting operations.
c. Conclusions The inspectors concluded that the drill performance was good and met' applicable
. paragraph a.3. portions of 10 CFR 50. Appendix R.Section I.However, communications were not successful.
S2 Status of Security Facilities and Eauioment The inspectors toured the protected area and observed that the perimeter fence was intact and not compromised by erosion nor disrepair. Isolation zones were maintained on both sides of the barrier and were free of objects which could shield or conceal an individual. The inspectors observed that personnel and packages
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entering the protected area were searched either by special purpose detectors or by a physical search for firearms, explosives and contraband. Badge issuance was observed, as was the processing and escorting of visitors. Vehicles were searched, escorted. and secured as described in the Plant Security Program (PSP) The inspectors verified that the security procedures addressed suspension of safeguards during emergencies in accordance with 10 CFR part 50.54 (X) and (Y). i The inspectors concluded that the areas inspected met the PSP requirements. ;
V. Manaaement Meetinas X. Review of UFSAR Commitments A recent discovery of a licensee operating its facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that com] ares plant practices, procedures, and/or
. parameters to t1e UFSAR description. While performing the inspections discussed in this report. the inspectors reviewed the applicable portions of the UFSAR that related to the areas ,
inspected. The inspectors verified that the UFSAR wording was ;
consistent with the observed plant practices, procedures, and/or parameters. No deficiencies were identified.
Enclosure 2
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50 l X.1 Exit Meeting Summary The inspectors presented the inspection results to members of the licensee *s management at the conclusion of the inspection on November 7. 1996. ,
The inspectors asked the' licensee representatives whether any information presented at the exit meeting could be considered '
proprietary. No proprietary information was identified. While some material identified as proprietary had been reviewed during the report period, no proprietary information is contained in the report.
X.2 Other NRC Personnel On Site On October 25. 1996. Johns P. Jaudon. Acting Deputy Director. DRP.
visited the site to observe activities associated with the maintenance rule baseline ins)ection conducted during the week of 0ctober 21. Also observing t1is inspection on October 24-25 was Richard P. Correia Chief. Reliability and Maintenance Section.
NRR. The results of this inspection are documented in NRC inspection report 50-321.366/96-12.
PARTIAL LIST OF PERSONS CONTACTED Licensee Anderson, J. , Unit Superintendent i Betsill J. Operations Manager !
Coggin. C.. Engineering Support Manager
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Curtis. S., Operations Support Superintendent Davis. D., Plant Administration Manager Fornel. P., Performance Team Manager Fraser. 0.. Safety Audit and Engineering Review Supervisor Hammonds J. , Regulatory Compliance Supervisor Kirkley W.. Health Physics and Chemistry Manager Lewis, J., Training and Emergency Preparedness Manager !
Moore. C.. Assistant General Manager - Plant Support ,
Reddick, R.. Site Emergency Preparedness Coordinator Roberts P., Outages and Planning Manager.
Sumner. H. , General Manager - Nuclear Plant Thompson, J., Nuclear Security Manager Tipps. S. Nuclear Safety and Compliance Manager Wells P., Assistant General Manager - Operations Enclosure 2
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INSPECTION PROCEDURES USED IP 37550: Engineering IP 37551:. Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving.. and Preventing Problems IP 42001: Emergency Operating Procedures IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 64704: Fire Protection Program IP-71001: Licensed Operator Requalification Program Evaluation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 82301: Evaluation of Exercises for Power Plants IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Followup - Operations IP 92902: Followup - Maintenance / Surveillance IP 92903: Followup - Followup Engineering IP 92904: Followw - Plant Support ITEMS OPENED. CLOSED. AND DISCUSSED Ooened 50-321.366/96-13-01 NCV Inadecuate Annunciator Response Procecure (Section 03.1).
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50-321.366/96-13-02 URI E0P Deviation From EPG step RC/P-3 (Section 03.2).
50-321.366/96-13-03 VIO Failure to Follow Procedures -
Multiple Examples (Sections 04.1.
M1.3, and R1.2).
50-321.366/96-13-04 IFI Inability to correctly classify events (Section 05.1).
50-366/96-13-05 VIO Failure to Properly Perform TS Surveillance 3.6.1.7.3 (Section l M3.2).
.50-321.366/96-13-06 IFI Additional Review of Wiring Deficiency on Electrical Connection Drawings (Section E2.2).
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Enclosure 2 L _ .- _
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Closed 50-321.366/96-13-01 NCV Inadecuate Annunciator Response Procecure (Section 03.1).
50-321.366/96-10-08 IFI Clarification of E0P Step RC/P-3 wording (Section 03.2).
50-321/96-04-01 VIO Failure to Complete Technical Specification Surveillance Procedure for Secondary Containment Integrity (Section 08.1).
50-321.366/96-04-02 VIO Failure to Follow Procedure - Two I Example (Sections 08.2 and M8.1).
50-321/96-02 LER Missed Technical Specification Surveillance on Secondary .
Containment Doors and Hatches !
(Section 08.3).
50-321/96-04-03 VIO Inadequate Procedure for ,
Operating the Reactor Core Isolation Cooling (RCIC) System From The Remote Shutdown Panel (RSDP) (Section E8.2).
50-321.366/96-06-09 IFI Review of DCR Work Deficiencies and Licensee Corrective Action (Section E8.4).
50-321.366/96-11-01 IFI Review of Engineering Evaluation on the Effects of Harmonics on EDG Operation (Section E8.1).
50-321.366/95-27-01 IFI Electro-Hydraulic Control (EHC)
System Problems (Section E8.5).
50-321/96-02-01 URI Emergency Diesel Generator (EDG)
Procurement ANSI Standard Issues (Section E8.6).
50-321.366/95-02-05 IFI Scope of Valves and Testing (Section E8.7).
50-321.366/95-25-01 IFI Valve Factor and Coefficient of Friction Issues (Section E8.8).
50-321/96-03 LER Component Failure Results in Unplanned Engineering Safety Feature System Actuation (Section E8.3).
Enclosure 2
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t LIST OF ACRONYMS USED ANSI - American National Standards Institute. Inc.
APRM - Average Power Range Monitoring ARP - Annunciator Response Procedure ASME - American Society of Mechanical Engineers-ATWS - Anticipated Transient Without Scram CFR - Code of Federal Regulations cm - centimeter C0F -
Coefficient of Friction (of valve stem threads)
CR - Control Room CRD - Control Rod Drive CS -
Containment Spray DCR - Design Change Request DP - Differential Pressure dpm - disintegrations per minute ED - Emergency Depressurization ED - Emergency Director EDG - Emergency Diesel Generator EHC - Electro-Hydraulic Control EIP - Emergency Implementing Procedures EMI - Electro-Magnetic Interference EOF - Emergency Operating Facility E0P - Emergency Operating Procedure EP - Emergency Preparedness EPG - Emergency Procedure Guidelines EPRI - Electrical Power Research Institute ERT - Event Review Team ES -
Engineering Support -
ESF - Engineered Safety Feature F - Fahrenheit FC - Flow Chart FME - Foreign Material Exclusion FSAR -
Final Safety Analysis Report GE - General Electric i GEMA - Georgia Emergency Management Agency l
GL - Generic Letter '
l GPC - Georgia Power Company
- Health Physics
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HP IFI -
Inspector Follcwup Itam IR -
Inspection Report
JPM - Job Perfor, nance Measure KVAR - kilovars KW - kilowatt ;
LC0 - Limiting Condition of Operation '
LER - Licensee Event Report LOCA - Loss of Coolant Accident l LOSP - Loss of Off-Site Power
. LPCI - Low Pressure Coolant Injection
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Enclosure 2
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MCCB - Molded Case Circuit Breaker MCR - Main Control Room MDC Minor Design Change MOV - Motor Operated Valve MWO - Maintenance Work Order NRC - Nuclear Regulatory Commission NRR - Nuclear Reactor Regulation OSC - Operations Support Center PA - Public Address PASS - Post Accident Sampling System PCM - Personnel Contamination Monitor PDR - Public Document Room PE0 - Plant Equipment Operator PMMS - P1 ant Modifications and Maintenance Support PSIG - Pounds Per Square Inch Gauge PSP - Plant Security Program PSTG - Plant Specific Technical Guidelines PSW - Plant Service Water System OC - Quality Control RAS - Recuired Action Statement RCA - Raciological Controlled Area RCIC - Reactor Core Isolation Cooling REA - Request for Engineering Assistance Rev - Revision RF - Refueling Floor RFPT - Reactor Feedwater Pump Turbine RG - Regulatory Guide RHR - Residual Heat Removal RHRSW -
Residual Heat Removal Service Water RPS MG - Reactor Protection System Motor Generator RPS -
Reactor Protection System RPV - Reactor Pressure Vessel RSDP - Remote Shutdown Panel RT - Radiographic Test RTP -
Rated Thermal Power SAE - Site Area Emergency SCBA - Self-Contained Breathing Apparatus SCOPE - Stop. Consider. Observe. Perform. Evaluate SCS - Southern Company Services SOR -
Significant Occurrence Report SR - Surveillance Requirement SS - Station Service SSC - Structures. Systems and Components TAF - Top of Active Fuel TM - Tem)orary Modification TRM - Tec1nical Requirements Manual TS - Technical Specifications TSC - Technical Support Center TSIP - Technical Specification Improvement Program UFSAR - Updated Final Safety Analysis Report Enclosure 2
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55 i URI - Unresolved Item
- UT - Ultrasonic Test
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VAC - Volts Alternating Current f VF - Valve Factor d
VIO - Violation
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Enclosure 2 i
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