IR 05000454/1998005
| ML20248L830 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 03/16/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20248L812 | List: |
| References | |
| 50-454-98-05, 50-454-98-5, 50-455-98-05, 50-455-98-5, NUDOCS 9803240256 | |
| Download: ML20248L830 (22) | |
Text
.
.
.
U. S. NUCLEAR REGULATORY COMMISSION REGIONlli i
Docket Nos: 50-454;50-455 License Nos: NPF-37; NPF-66 Report No:
50-454/98005(DRP); 50-455/98005(DRP)
Licensee:
Commonwealth Edison Company Facility:
Byron Generating Station, Units 1 and 2 Location:
4450 N. German Church Road Byron,IL 61010 Dates:
January 13 - February 23,1998 inspectors:
E. Cobey, Senior Resident inspector N. Flitton, Resident inspector T. Tongue, Project Engineer C. Thompson, Illinois Department of Nuclear Safety Approved by: Michael J. Jordan, Chief Reactor Projects Branch 3 l
l l
l l
9803240256 900316 i
PDR ADOCK 05000454 G
PDR l
L-
_ _ - - _ - - _ _ - - - - - - - -
- -. - - - - - - - -
- - - - - -
- - - - - - - - - - - - -
--
- - - -
-
J
.
%
i EXECUTIVE SUMMARY Byron Generating Station Units 1 and 2 NRC Inspection Repon No. 50-454/98005(DRP); 50-455/98005(DRP)
This inspection included aspects of licer see operations, maintenance, engineering, and plant
,
support. The report covers a six-week period of resident inspection.
j Operations i
The inspectors concluded that an out-of-service error on the chemical and volume control
+
system occurred due to poor communication between the involved operators, assigning multiple tasks to be performed concurrently, and a perceived pressure to accomplish work rapidly. Although licensee identified, a violation was cited because this was a i
repetitive issue. (Section O1.1)
The inspectors concluded that the nuclear station operators (NSOs) were working large
+
amounts of hours just under the overtime guidelines for extended periods of time. The inspectors did not identify any significant deviation from the overtime guidelines.
However, the inspectors concluded that generally, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts worked by the NSOs caused large amounts of overtime hours and the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shifts caused long periods of work without a day off. Additionally, the 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> shifts caused excessive shift rotations.
The inspectors concluded that the large amounts of hours worked by some NSOs and the extra shift rotations caused by the 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> shifts were poor human factor practices.
(Section 01.2)
Maintenance / Surveillance The inspectors concluded that the licensee's recovery plan after identifying a main
.
condenser tube brush in the containment spray system was appropriate. However, the brush represented another example of continuing poor foreign material exclusion controls by the station. Numerous examples of foreign materialin plant systems were identified by the licensee and quality and safety assessment group during the refueling outage. The inspectors concluded that NSWP-A-03, * Foreign Material Exclusion," Revision 0, was inadequate to prevent the intrusion of foreign materialinto safety-related systems. A violation was issued. (Section M1.1)
Observed maintenance and surveillance activities were well conducted. Procedures
were used and personnel were knowledgeable. Surveillance tests were properly authorized and coordinated. Good communications were observed between operators.
(Sections M1.2 and M1.3)
The inspectors concluded that maintenance personnel did not follow station procedures;
+
specifically, an engineering request was not prepared to get engineering approval prior to installing a gasket in a the 1B and 28 essential service water pumps. Additionally, the l
mechanics work procedure did not discuss the use of a gasket. The inspectors concluded that appropriate design control measures had not been taken prior to adding
!
the gasket. A violation was issued. (Section M1.4)
!
,
!
\\
_ - _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - -
. _ _ _..
._.
)
s l'
Enaineerina i
The inspectors concluded that the design control of the DG was poor in that the fullload
+
possibility was not considered in the modeling for the replacement govemors.
- (Section E1.1)
A safety evaluation was not performed prior to venting the 28 charging (CV) pump into
+
the volume control tank (VCT) and eventually venting the VCT to the gaseous waste processing system (GWPS) as discussed in Inspection Report No. 97022. This was not in accordance with the intended purpose of the GWPS system as described in the UFSAR. The item was unresolved pending further NRC review. The NRC review concluded that this matter constituted a violation of 10 CFR 50.59 for failure to conduct a safety evaluation prior to allowing a portion of the CV system to be vented to the VCT and ultimately to the GWPS. A violation was cited. (Section E8.3)
Plant Support Based on discussions with the Fire Marshal and seven inspector identified examples of
failing to adhere to procedures, the inspectors concluded that the transient combustible material control procedures had been interpreted to allow various practices that were not in accordance with the procedures. The inspectors were concerned that fire protection procedures were not being followed due to the number of verbal interpretations that the inspectors identified. Three violations were cited. (Section F1.1)
.
>
'
______
_ _ _ _
L.'
\\
Report Details
!
!
Summary of Plant Status Unit i remained shutdown for the steam generator replacement and refueling outage that began November 7,1997. Unit 2 operated at or near full power for the duration of the inspection period.
I. Operations
.
Conduct of Operations l
01.1 Chemical and Volume Control (CV) System Out-of-Service (OOS) improper Clearance
[
a.
Inspection Scope (71707)
The inspectors reviewed the circumstances surrounding the improper clearance of OOS No. 970006915. The inspectors interviewed operators and reviewed applicable documentation and procedures including Byron Administrative Procedure (BAP) 330-1, " Station Equipment Out-of-Service Procedure," Revision 28, b.
Observations and Findinas On January 21,1998, during the performance of Byron Operating Procedure (BOP) CV-M1C, " Chemical and Volume Control System Valve Lineup," Revision 4, an operator identified that the Unit 1 seal water return filter 1CV02F inlet isolation valve, 1CV8396A, was OOS closed; however, the valve was expected to have been in the open position. The licensee subsequently determined that the associated OOS,970006915, had been cleared on January 17,1998, in addition, the licensee identified that three other components had not been returned to service in accordance with OOS No. 970006915, including the Unit 1 seal water retum Filter 1CV02F bypass valve, i
1CV8399; the control switch for the reactor coolant pump seal water retum containment isolation valve,1HS-CV057; and the control switch for the reactor coolant pump seal water retum isolation valve,1HS-CV082. The licensee corrected the OOS, completed a valve lineup, and initiated problem identification form (PlF) B1998-00313.
The non-licensed operator (NLO) had been directed to perform three sepcrate tasks while in the Unit 1 containment, one of which was to retum to service the Unit 1 reactor coolant pump sealleakoff header inside containment in accordance with OOS 970006915. Upon completion of the tasks, the NLOs notified the nuclear station operator (NSO) that the seal retum OOS was completed and requested that the NSO sign off the OOS checklist.
As a result of not utilizing 3-way communication techniques and confirming the information provided, the NSO signed off the entire OOS as being completed when only the components inside the containment had been returned to service. Consequently, the remaining components on the OOS were not retumed to service. In addition, the NSO indicated that another contributor to the OOS error was the distraction created by performing multiple tasks concurrently in an attempt to get as much work done as possible.
l l
r
.
.'
\\
During inspection of this OOS error, the inspectors noted that during the last six month period, the licensee identified numerous deficiencies in the implementation of the OOS program, including at least four examples of deficiencies in the clearance of
{
out of services associated with nonsafety-related equipment. Byron Administrative Procedure (BAP) 330-1, " Station Equipment Out-of-Service Procedure," Revision 28, Section C.6.c.4, required, in part, that the equipment listed on the out-of-service form be retumed to service. The failure to return to service OOS 970006915 was considered a violation of Technical Specification (TS) 6.8.1.a (50-454/455-98005-01a(DRP)), as described in the attached Notice of Violation.
!
c.
Conclusions l
The inspectors concluded that an out-of-service error on the chemical and volume control system occurred due to poor communication between the involved operators, assigning multiple tasks to be performed concurrently, and a perceived pressure to accomplish
work rapidly. Although licensee identified, a violation was cited because this was a j
repetitive issue.
.
l 01.2 Licensed Overator Overtime Control
!
a.
Inspection Scope (71707)
l l
l The inspectors reviewed the overtime hours for seven nuclear station operators (NSOs)
and three senior reactor operators (SROs) for the period November 7,1997, until February 2,1993. The period, almost 12 weeks, was entirely an outage period for Unit 1.
l The inspectors sample included the operators with the highest amount of overtime hours as documented by the licensee. The inspectors also reviewed the data for total hours inside the protected area, number of days in a row an operator worked, number of hours worked in 7-day periods, and the number of 16-hour days worked by the NSOs.
b.
Observations and Findinos The inspectors noted that until January 5,1998, operators were on 12-hour shifts.
Beginning January 5, the licensee changed the NSOs to 8-hour shifts with the SROs remaining on 12-hour shifts, l
The inspectors noted that the 7 NSOs worked greater than 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> during several 7-day periods. Each of the 7 NSOs worked 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> or more, an average of 5 weeks during the 12 weeks reviewed. Each operator worked greater than 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> in back-to-back 7-day periods at least once, with the most significant examples being where twice individuals worked greater than 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> 2 weeks straight and one individual worked greater than 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> 3 weeks straight.
i Several examples were identified by the inspectors where the NSOs worked a large number of days in a row without a day off. The inspectors counted 13 examples of the NSOs working greater than 9 days straight without a day off. Typically, work periods without a day off were 14 to 16 days with one exception of 32 days. Several examples were noted where operators worked day shift, were off swing shift, then worked a midnight and day shift.
_ _ _ _ - _ - _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.
'
.
l l
The inspectors also noted that the amount of overtime varied greatly between operators.
l The licensee data indicated that the NSO with the largest amount of overtime for 1997 l
worked almost 2% times more overtime hours than the NSO with the smallest amount of overtime, i
The inspectors did not identify any significant deviation from the overtime guidelines of l
Generic Letter 82-12 and Byron Administrative Procedure (BAP) 100-7, " Overtime
'
Guidelines," Revision 11. However, the inspectors concluded that, generally, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts worked by the NSOs prior to January 5,1998, caused large amounts of overtime
,
hours and the change to 8-hour shifts has caused long periods of work without a day off.
The overtime hours for the tnree SROs reviewed appeared well controlled.
c.
Conclusions The inspectors concluded that the NSOs were working large amounts of overtime hours, and just under the overtime guidelines for extended periods of time. The inspectors did not identify any significant deviation from the overtime guid6 ;nes. However, the inspectors concluded that, generally, the 12-hour shifts worked by the NSOs caused large amounts of overtime hours and the change to 8-hour shifts caused long periods of work without a day off. Additionally, the 16-hour shifts caused excessive shift rotations. The inspectors concluded that the large amounts of hours worked by some NSOs and the extra shift rotations caused by the 16-hour shifts were poor human factor practices.
Miscellaneous Operations issues (71707,92700,92901)
08.1 10 CFR 50.54(f) Letter Commitment Review a.
Inspection Scope The inspectors reviewed the status of commitments pertaining to Byron's March 28, 1997, response to the NRC's request for information pursuant to 10 CFR 50.54(f). The commitment numbers correspond to those used by the licensee in their March 28,1997, response.
b.
Observations and Findinas b.1 Commitment 1 and 322: "To reinforce these principles and ensure that performance results were achieved, the CNOO [ Chief Nuclear Operation Officer) conducts Management Review Meetings (typically each month) at each site. These meetings are focused on safety performance and the effectiveness of improvement initiatives. During these meetings, NOD [ Nuclear Operations Division) executive management challenges site management on the adequacy of their plans and reinforces accountability for
,
achieving performance results."
The inspectors attended the January 1998 Management Review Meeting (MRM). The meeting was chaired by the Commonwealth Edison President of the Nuclear Generation Group. The Pressurized Water Reactor (PWR) Operations Vice President also attended.
The inspectors noted that an organizational change in Commonwealth Edison replaced the CNOO with the PWR Operations Vice President. The inspectors noted the me3 ting
!
l
.
_ _ _ _.. _ _. _ _ _ _ _ _.. _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _. - - _ _
_ _ _ -
. _ _
_
_. __ _ _ _ _ _ _ _ _ _ _ _ _. _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
l
!
l
l
was focused on safety and reviewed the effectiveness of improvement initiatives. Station management was challenged on the adequacy of their plans and accountability was stressed by the President.
b.2 Commitment 75 and 271: "The CNOO conducts Management Review Meetings at each site focused on safety performance and the effectiveness of improvement initiatives.
l These meetings address trends of safety, performance, and cost indicators; results of l
third party (NRC and INPO) inspections; results of site self-assessments; status of
material condition in the plant; outage planning and performance; and assessments of the
!
quality of workforce product and training."
The inspectors noted that the January 1998 MRM discussed each of the items identified in commitment 75 and 271, b.3 Commitment 100: "Each of the performance indicators described in Sections 4.7.1 and 4.7.2 in the letter of March 28,1997, will be monitored by the Site Vice Presidents, and will be reviewed during the periodic Management Review Meeting for each station."
The inspectors observed that the licensee did not discuss each of the indicators as described in Commitment 100. However, the indicators that were "in variance," or not meeting the prescribed goals, were discussed in detail. The. inspectors noted that
Commitment 101 stated the Site Vice President would submit a monthly letter to the PWR
'
Vice President reporting the status of all the indicators. Commitment 101 also indicated that if performance criterion were not met, the cause of the deviation would be presented as part of the next MRM meeting. The inspectors concluded that the commitment numbering was not exact and the licensee was meeting the intent of the commitment.
i b.4 Commonwealth Edison Board of Directors Nuclear Oversiaht Committee: On October 23, 1997, the Acting Director, Division of Reactor Projects -Ill/l\\/, NRR, observed a meeting between the licensee's senior executives and the Nuclear Oversight Committee (NOC).
The licensee presented performance information for each of the facilities, much of which was presented to the NRC at a public meeting in Region lit on October 24,1997. The NOC asked the executive probing questions, challenging them on issues such as root cause determination and dissemination of event data across sites.
c.
Conclusions
,
l The inspectors concluded that the management review meeting was being conducted in accordance with the 10 CFR 50.54(f) response, and items 1,75,100,271, and 322 are considered closed at Byron.
08.2 (Closed) Unresolved item (50-454/455-95007-01(DRP)): Review of the licensee's root cause determination of the electrical fuse control program which did not require documentation of reinstalling a removed fuse. Initialinspection showed that the program requirad documentation of who, why, and when a fuse was removed. Therefore, the licensee's action was to have the future fuse removals tracked by the Out-of-Service l
l program rather than the Caution Card program. This created a requirement to document
!
the restoration. Training was also provided to the appropriate personnel and labeling was improved on the affected fuse block. This issue is closed.
_
i
'
s
!
08.3 (Closed) Violation (50-454/455-96003-02(DRP)): Controlled Leakage TS Violation. The licensee implemented corrective actions by changing the operating procedure; BOP CV-10, "CV Filters-Isolation and Return to Service," and annunciator response procedures BAR 1-7-A2 and BAR 2-7-A2, for "RCP Seal Water injection Filter DP High."
The change provided instructions to operators to notify the Station Control Room i
l Engineer to initiate the performance of % BOS 4.6.2.1.c-1, " Reactor Coolant System Monthly Controlled Leakage Surveillance" after the filters had been realigned. Placards were placed on filter inlet, outlet and bypass valves with the same instructions.
Discussions were also provided on the events for alllicensed operators and system
,
l engineers. The inspectors reviewed these actions and found them acceptable. This violation is closed.
08.4 (Closed) Violation (50-454/455-96005-01(DRP)): Unexpected Dilution of Unit 1. The j
l licensee's short term corrective actions consisted of: writing a special plant procedure, j
SPP 96-043, for boron dilution with the reactor coolant loops isolated; requesting and obtaining self-assessments from the people involved in the events; enhancing contro!
room shift briefs regarding reactor safety and reactivity management; developing a daily order for operators to notify and obtain permission from the duty SCRE for all reactivity changes; and counseling the individuals directly involved in these events. Long term l
corrective actions included developing new procedures and enhancing existing procedures to account for dilutions with the loop stop isolation valves shut and while on shutdown cooling, counseling alllicensed operators on the root cause and management's expectations, and modifying the reactivity management administrative procedure. The following procedures were created or modified; BOP CV-5 " Operation of the Reactor Makeup System in the Dilute and Alternate Dilute Mode," BOP CV-6 " Operation of the Reactor Makeup System in the Borate Mode," BOP CV-7 " Operation of the Reactor Makeup System in the Auto Makeup or Manual Mode," and BOP CV-25 "RCS Blended Flow Additions With No Reactor Coolant Pumps in Operation." The corrective actions
!
and procedures were reviewed by the inspectors and found to be acceptable. This violation is closed.
08.5 (Closed) Violation (50-454/455-96007-02(DRP)): Inadequate Procedure Regarding Essential Service Water Cooling to the 2A CV Pump Lube Oil Cooler. This violation resulted from an inadequate procedure and an operator error for failure to use an additional existing procedure to perform a proper system lineup. Corrective actions by the licensee consisted of revising 2BVS 1.2.3.1-1 " Unit 2 Train A, ASME Surveillance Requirements for Centrifugal Charging Pump 2A and Chemical and Volume System Valve Stroke Test"; counseling the involved operators and supervisors; and developing additional procedural guidance for aligning, startup, and running a CV pump on recirculation.
A review by the licensee resulted in changes to the following procedures to ensure proper CV pump alignment and startup in the future:
2BVS 1.2.3.1-1-2a, "CV Pump ASME Surveillance"
-
2BVS 1.2.3.1-2-2b, "CV Pump ASME Surveillance"
-
1BVS 1.2.3.1-1.1a, "CV Pump ASME Surveillance"
-
1BVS 1.2.3.1-2-1b, "CV Pump ASME Surveillance"
-
BOP CV-1a, "Startup of the CV System (Unit One)"
-
BOP CV-1b, "Startup of the CV System (Unit Two)"
.
-
i
_ - _ _ _ - - _ _ _ _ _ _ _ _ _ _. _ _ - _ _ _ _ _ _. _
.
l i
The inspectors reviewed the licensee's actions and found them to be acceptable. This violation is closed.
11. Maintenance M1 Conduct of Maintenance l
l M1.1 Foreian Material Exclusion Controls a.
Inspection Scope (62707)
l l
The inspectors reviewed the licensee's foreign material recovery plan after mechanical maintenance mechanics found a plastic condenser tube cleaning brush inside a Unit 1 containment spray (CS) valve. The inspectors also reviewed NSWP-A-03, " Foreign Material Exclusion," Revision 0, licensee identified issues during the refueling outage, and Quality and Safety Assessment (Q&SA) foreign material exclusion (FME) findings l
identified during the outage.
b.
Observations and Findinas The licensee had indications of a leaking containment spray valve during the previous operating cycle. The refueling water storage tank experienced slightly elevated sodium levels and the spray addition tank levelincreased during the cycle. Motor operated valve testing on 1CS019A, CS Eductor Addition Valve, performed during the refueling outage j
determined that the valve had approximately 0.66 gallon-per-hour seat leakage. On l
January 21,1998, the licensee opened 1CS019A and found the pieces of a plastic brush
'
inside the valve body. The CS piping supplied the sodium hydroxide to the eductor. The
,
brush appeared to be a used for cleaning main condenser tubes and had been broken into two pieces, apparently by the disk of the valve.
The licensee developed a foreign material recovery plan. Actions include initial disassembly of two additional valves to allow a boroscope inspection of the spray additive l
piping and inspection of both the spray additive tank and the refueling water storage tank.
Additionally, the licensee performed a surveillance test to verify the proper amount of sodium hydroxide flow. No additional foreign material was identified in the piping or the tanks and the flow setting was the same as previously established. Therefore, the licensee concluded that there was no additional foreign materialin the system.
A surveillance test to set the sodium hydroxide flow amount was performed in June 1997.
This surveillance substituted primary water for the sodium hydroxide solution. In order to use the primary water, a hose was connected from a primary water connection to the test l
connection in the spray additive portion of the CS system. System engineering believed l
that the hose used had previously been used to drain a water box of the main condenser l
(circulating water). The brush was most likely in the hose after draining the water box and then moved into the CS system during the June 1997 surveillance test.
The inspectors reviewed NSWP-A-03," Foreign Material Exclusion," Revision 0, and did not identify any steps that may have prevented the introduction of the brush into the CS system. The licensee noted that typically a surveillance would require use of a new hose
l
_ __ _-.___ __ _ - _ _ _ _ _ _ _
.
to prevent cross contamination between clean and dirty systems; however, the licensee also noted that there was not a separate process, requirement, or steps in NSWP-A-03 that would have prevented the brush from entering the CS system. The inspectors noted that 10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings,"
required that activities affecting quality shall be prescribed by documented instructions..
. of a type appropriate to the circumstances. The inspectors concluded that NSWP-A-03 was not of a type appropriate to the circumstances in that the procedure failed to prevent the introduction of a brush into the CS system. The inspectors noted that violations for FME issues had been previously cited in NRC Inspection Report Nos. 50-454/455-97002, 97015, and 97022. The inspectors concluded that the failure to prevent the introduction of the brush into the CS system was a violation of 10 CFR Part 50, Appendix B, Criterion V (50-454/455-98005-02(DRP)).
j The licensee identified and documented on problem identification forms at least nine examples of foreign materialintrusion problems during the Unit 1 steam generator replacement outage. The licensee's Quality and Safety Assessment (Q&SA) group also identified several foreign material control deficiencies. Corrective Action Record (CAR) 6-98-002 was issued on January 22,1998, by Q&SA to document their findings.
At the end of the inspection period, the station response to the CAR had not been issued.
.
'
The licensee stated that a revision to NSWP-A-03 was in progress, with support from the senior station managers, and scheduled to be issued in April 1998.
l c.
Conclusions I
The inspectors concluded that the licensee's recovery plan after identifying a main condenser tube brush in the containment spray system was appropriate. However, the brush represented another example of continuing poor foreign material exclusion controls by the station. Numerous examples of foreign material in plant systems were identified by the licensee and quality and safety assessment group during the refueling outage. The inspectors concluded that NSWP-A-03, " Foreign Material Exclusion," Revision 0, was inadequate to prevent the intrusion of foreign material into safety-related systems. A violation was issued.
l M1.2 Maintenance Observations (62707)
a.
Inspection Scope I
The inspectors observed the performance of all or portions of the following work requests (WR). When applicable, the inspectors also reviewed TSs and the Updated Final Safety Analysis Report (UFSAR) for potential issues.
WR 970114422-01 Replace the "A" train reactor trip breaker
+
WR 970078183 Replace the inboard seal on the 1B Essential Service
+
Water (SX) Pump WR 960100631 Repair oilleak on the 1B SX Pump Attached Lube Oil Pump
+
WR 960098236 Preventive maintenance and VOTES testing on 2CS0098,
+
2B CS Pump containment sump recirculation valve
_
_ _ _
. - _ _ _ _ - _. _,
.
.
c.
Conclusions During the inspectors observations, procedures were used and maintenance personnel were knowledgeable. The inspectors concluded that observed maintenance activities were well conducted.
M1.3 Surveillance Test Observations (61726)
a.
Inspection Scope The inspectors observed the performance 6f all or parts of the following surveillance test procedures.
2BOS 3.1.1-20 Unit 2 Train A Solid State Protection System Bi-monthly
+
Surveillance (Staggered)
OBVS XDP-5 Charcoal Absorber 720 Hour Check.
+
1BVS 0.5-2.SI.2-1 Emergency Core Cooling System (ECCS) Check Valve Stroke
+
Test 1BVS 5.2.h.2-1 ECCS Flow Balance Test
+
OBOS 7.5.e.1-1 OB SX Make-up Pump Auto Start
+
1BVS 5.2.d.2-1 Unit i VisualInspection of the Containment Recirculation
+
Sumps c.
Conclusion The inspectors concluded that all components were tested satisfactory and met the procedure's acceptance criteria. The surveillance were completed in a timely manner, met regulatory requirements, and the components remain operable.
M1.4 Essential Service Water (SX) Pump 1B Shaft Axial Oscillations (71707. 62707)
l a.
Inspection Scope During a routine auxiliary building inspection, the inspectors noted that the 18 SX pump shaft was oscillating axially while the pump was running. The inspectors reviewed the licensee's operability assessments (98-03 and 98-09) and PlFs B1998-00111 and B1998-00434. The inspectors also observed portions of the licensee's repairs, reviewed WR 960030886, "Oilleak at pump outboard bearing assembly," and had several discussions with the system engineer and mechanical maintenance department head.
b.
Observations and Findinas On January 8,1998, the inspectors noted that the 1B SX pump was oscillating axially.
The licensee investigated the inspectors observation and determined that the pump vibration data was higher than nominal, but acceptable. The SX pump was running with a reduced flow through the pump due to system configuration. The licensee varied the l
pump flow and determined that the oscillations only existed at the reduced flow. At i
normal pump flow, the oscillations stopped. Based on the vibration data and normal bearing temperature indications, the licensee determined the pump was operable but maintained the normal flow through the pump when the pump was running.
_ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _
.
- _ - - _ _ _ _ _ _ _ _ _
e
-
f The licensee's investigation fnund that the axial end play for the pump shaft was 0.035 inches, significantly greater than the vendor recommendation of 0.006 to 0.008 inches. The licensee disassembled the thrust bearing and discovered a 0.030 inch thick gasket installed that was not specified on the drawing. The thrust bearing inspection did not identify any significant wear. After removing the gasket, the licensee retumed the pump to service and could not repeat the oscillations. The licensee concluded that the gasket was the cause of the shaft oscillation.
The licensee inspected the other SX pumps and determined that the 28 SX pump had a gasket installed in the same location that caused the oscillations on the 1B SX pump. An operability assessment was prepared that concluded the 28 SX pump was operable due to the style of thrust bearing, the style of the pump coupling, and the large internal clearances of the pump. The operability assessment also stated that the gasket should l
l be removed at the next opportunity. The inspectors found the operability assessment acceptable.
The system engineer identified a work package, WR 960030886, that documented installation of the gasket in the 18 SX pump. However, there was not a requirement to use a gasket in the procedure nor was there any engineering approval to use the gasket.
The mechanic that installed the gasket could not remember performing the work in July i
1996. However, both the system engineer and mechanical maintenance department head agreed that the extra gasket was probably used to help stop oilleakage. At the end of the inspection period, the licensee had not determined when the gasket was installed on the 2B SX pump but had scheduled a work period to remove it.
The inspectors noted that BAP 1610-9, " Engineering Requests," Revision 4, identified when engineering requests (ERs) were used and the process to submit, complete, and control the ERs. Paragraph C.2 listed design changes (modifications, minor plant changes, exempt changes) as an example of when an ER was required. The inspectors concluded that the plant configuration was altered without engineering approval and that the mechanics should have received engineering approval prior to installing a gasket to stop the oilleak. The licensee agreed that an ER should have been used to make the appropriate decision regarding use of the gasket. The inspectors concluded that the failure to submit an ER prior to installing a gasket in the 1B SX pump was an example of a TS 6.8.1.a violation for failure to follow Procedure BAP 1610-9 (50-454/455-98005-01b(DRP)).
During discussions with the licensee, the licensee also noted that no requirement existed in the work request to use a gasket. Based on the absence of the requirement, licensee management believed that the mechanic should not have used a gasket. Since the gasket was installed on the 1B SX pump in 1996, the licensee believed that current procedure adherence standards would prevent installation of a gasket without written work instructions. Since the time of installation of the gasket on the 2B SX pump was not clear, the inspectors were not certain that current procedure adherence standards would prevent a recurrence.
,
During a portion of the licensee's investigation, the inspectors observed two pipe caps l
removed from the 18 SX pump discharge strainer inlet and outlet pressure gage piping.
The inspectors noted that there were not any foreign material exclusion measures in place to prevent objects from entering the instrument piping. The 1B SX pump had been
l
.
.'
.
l isolated and drained for the investigation. When questioned, the licensee believed that the caps had been removed to support venting the isolated portion of the system while the draining was in progress and the inspectors agreed. During the inspectors observations, the area was unattended. The inspectors were concemed that debris could enter the SX instrumentation piping and prevent proper indication. NSWP-A-03 did not clearly address FME controls while venting a system. The inspectors concluded that, although a procedure violation was not identified, the practice of not protecting a vent path was poor FME practice. See Section M1.1 for additional discussion of FME practices.
c.
Conclusions The inspectors concluded that maintenance personnel did not follow station procedures; specifically, an engineering request was not prepared to get engineering approval prior to installing a gasket in a the 1B and 2B essential service water pumps. Additionally, the mechanics work procedure did not discuss the use of a gasket. The inspectors concluded that appropriate design control measures had not been taken prior to adding the gasket. A violation was issued.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) LER 50-454/95-010-00: Chemistry Sample Was Not Representative Due to a Closed Valve. This event resulted while trouble shooting an electrical power supply and the circuit breaker was found open and, thus, the affected valve was forced closed. The l
unexpected chemistry results were promptly identified by the licensee, investigated, and corrected. In addition, the licensee held discussions with the operations and maintenance departments to assure that changes such as opening a circuit breaker for trouble shooting are properly logged.
Byron Administrative Procedure (BAP) 340-2," Initiation and Use of System Lineups (Mechanical and Electrical)," Step C.10.a, required the use of BAP 340-2T5, " Abnormal Component Position Log," to record the status of a component that will be in an abnormal position beyond a shift turnover. Byron Administrative Procedure 400-9," Troubleshooting
'
and Maintenance Alterations," Step F.4.c.3, required, in part, that all alterations to plant equipment during troubleshooting be documented on the Maintenance Alterations Log i
(BAP 400-9TS). This event resulted from a failure of operations and maintenance personnel to log the change in position of the circuit breaker for the affected chemistry sampling valve. This was a violation of 10 CFR Part 50, Appendix B, Criterion V, requiring that procedures be developed, implemented and followed for activities affecting quality in a nuclear power plant. However, this failure constituted a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy (50-454/455-98005-03(DRP)). This LER is closed.
!
_ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ - _ _ _ _ _ _ _ _ -
-
'
.
.
.'
,
Ill. Enaineerina i
E1 Conduct of Engineering E1.1 Emeraency Diesel Generator Desian Control (61726)
a.
Inspection Scope
l During the licensee's preparations for diesel generator (DG) load sequencer testing, the inspectors questioned the use of recirculation flow paths, or mini-flow, for each load sequenced on the DG during the test. The inspectors discussed the issue with the system engineer and engineering manager on several occasions.
j b.
Observations and Findinas i
On December 12,1997, the inspectors noted that the diesel generator (DG) sequence test for the 1 A DG was conducted with the emergency core cooling system (ECCS)
pumps in a recirculating mode. During a design basis accident, ECCS pumps, including
)
auxiliary feedwater (AF), start in an injection mode. During each refueling outage, the DGs are disassembled and inspected. The inspectors questioned whether the DG sequence test was adequate to establish operability after each outage if the sequence j
test was performed with the ECCS pumps in a recirculation line-up. The licensee
-
discussed the issue with the inspectors again on January 6,1998, and stated that there was not an analysis that showed the DG would perform as designed. The licensee stated that a pre-operational test was conducted with full flow injection; however, DG performance trending for transient loading performance had not been performed since initial plant startup. The "A" train AF pump was the last significant load in the starting sequence and caused the most significant dip in electrical frequency. The inspectors noted that the licensee replaced the Unit 1 DG govemors during the previous refueling outage in April and May 1996. The post modification testing used the sequence test with the ECCS pumps in recirculation.
On January 27,1998, the licensee wrote a PIF that documented the inspectors concerns.
The licensee determined that the Unit 2 DGs were operable and that the Unit 1 DGs were operable while in cold shutdown. Additional modeling of the Unit 1 DG govemor response was completed using design basis brake horsepower for each of the ECCS loads sequenced onto the DG. The modeling identified that with the actual design basis loading, the margin in the time delay feature of the underfrequency DG trip was removed.
The time delay was 1.0 second and with the allowed relay setting, the model indicated the frequency would be below the underfrequency trip relay setpoint, which could have been
,
set as high as 57.5 hertz, for approximately 0.9 second. Although the DG was operable, the licensee decided to extend the time delay of the underfrequency trip from 1.0 second to 2.5 seconds to restore the margin in the delay.
. _ _ - _ _ _ - _ _ _ - _ -
_ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _________________-__-_- __ _ __ _ _____ _ __ _- _ _ _ _ _ _ _ _ _ - _
l
,*
.'
l l
l c.
Conclusions
!
l The inspectors concluded that the design control of the DG was poor in that the full load l
possibility was not considered in the modeling for the replacement govemors in 1996.
E2 Engineering Support of Facilities and Equipment (50001)
l E2.1 Unit 1 Containment Tendon Restoration Difficulties a.
Inspection Scope During the replacement of tendons in the Unit 1 containment after the containment opening was restored for steam generator replacement, two tendons became stuck, e.g.,
!
could not pass through the sheathing. The inspectors discussed the issue with the licensee and observed the licensee's attempts to free the tendons.
,
I
!
b.
Observations and Findinas During the replacement of tendons in the Unit 1 containment after the containment opening was restored, two tendons became stuck. The inspectors observed that the two tendons became stuck when they were approximately 75 percent installed. After numerous attempts to free the tendons, the licensee decided to excavate the containment concrete at the locations the tendons were believed to be stuck.
The licensee believed that damage to the metal sheathing occurred at several locations.
The licensee cut into the concrete at the location of each obstruction and removed portions of sheathing that had crumpled and plugged the tendon tunnel. The licensee
,
l concluded that when the tendons were being reinserted, they caught portions of the
'
sheath that may have been damaged previously.
l The licensee planned to remove the damaged portion of the sheathing and reseal the concrete tendon tunnel. This would have left several feet the tendon tunnel upstream of the obstruction with no sheathing. The tendons were to be reinserted and packed with grease. The inspectors questioned whether tendon tunnels with part of the sheathing removed would effectively contain the grease or whether the grease would leak into the concrete, possibly degrading it and exposing the tendon wires to potential corrosion.
During discussions with the NRC on February 6,1998, the licensee stated that: (1) the metal sheathing liner was intended primarily as a form to preserve the opening for the tendons when the containment concrete was poured, and not as a barrier to contain the grease; (2) the grease used to protect the tendons congeals at 135 degrees Fahrenheit l
which greatly reduces its fluidity; (3) the tensioning of the tendons causes closure of l
cracks in the concrete further reducing the chance of the grease penetrating the concrete; and (4) a study by Oak Ridge National Laboratories and the American Concrete institute
,
l determined that tendon grease does not adversely impact the containment concrete.
l Based on the discussions with the licensee, the inspectors did not identify any significant
!
safety issues. Subsequently, the licensee agreed to specifically monitor their condition I
by including at least one of the two tendons in future surveillance.
- s f
.
c.
Conclusions The inspectors concluded that the licensee's actions were appropriate.
E8 Miscellaneous Engineering issues (92700, 92903) -
E8.1 (Closed) Violation (50-454/455-95-009-01(DRP)): Failure to have an integrated leak test on potentially highly radioactive systems outside containment. The licensee revised existing procedures and created new procedures to include leakage acceptance criteria for the systems involved which included quantification and documentation of the test results. In addition, the revised training for system engineers and inservice Inspection personnel training included quantification and documentation requirements. Since the violation was issued, the results of subsequent tests have been acceptable. This violation is closed.
E8.2 (Closed) Unresolved item (50-454/455-96003-07(DRS)): Could Essential Service Water (SX) system perform it's intended function with plugged strainers due to potential lack of strainer backwash capability? In response to Generic Letter GL 89-10, the licensee eliminated a number of motor operated valves (MOV) from the formal MOV program.
Four of these valves were for SX strainer backwashing. The licensee modified the associated backwashing procedure to ensure that an operator was present to manually initiate and secure the SX strainer backwash process. The procedure also has instructions to manually override the MOV if necessary. The inspectors questioned the
-
ability for an operator to gain access to the SX pump room under accident conditions in that radiation levels may be excessively high. The licensee provided an analysis based on UFSAR information that showed that access was possible. This URIis closed.
E8.3. (Closed) Unresolved item (50-454/455-97022-03(DRP)): 2B CV Pump Fill and Vent Safety Evaluation. The licensee had not completed a safety evaluation prior to venting the 2B CV pump into the volume control tank (VCT) and eventually venting the VCT to the gaseous waste processing system (GWPS). This was not in accordance with the
)
intended purpose of the GWPS system as described in the UFSAR. This item was
'
unresolved pending further NRC review. The NRC review concluded that this matter constituted a violation of 10 CFR 50.59 for failure to conduct a safety evaluation prior to allowing a portion of the CV system to be vented to the VCT and ultimately to the GWPS.
The Unresolved item is closed and subsequent action will be tracked under the violation
,
(50-454/455-98005-04(DRP)).
IV. Plant Support l
F1 Control of Fire Protection Activities (71750)
l F1.1 Control of Combustible Materials a.
inspection Scooe j
i During routine plant inspections, the inspectors identified several transient combustible
concems.' The inspectors reviewed BAP 1100-9, " Control, Use, and Storage of Flammable and Combustible Liquids and Aerosols," Revision 4; BAP 1100-7, " Fire
<
_. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ - _ _ _ _. _
'
_ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ - _ _ - _ _
%
,'
.
Prevention for Transient Combustibles," Revision 8; and PlF B1998-00573. The inspectors had several discussions with the Fire Marshal conceming the issues described below.
b.
Observations and Findinas During a surveillance test observation on February 4,1998, the inspectors noted several combustible material control issues. The following were observed in the river screen house (RSH): numerous oily rags and a length of oily tygon tubing filled a large, uncovered, plastic trash can; two 1-gallon containers of cleaning agent identified as combustible were sitting on the floor; and three aerosol cans of spray paint that were not in a storage container. The inspectors also noted two 55-gallon barrels of oil without transient fire load permits; however, the inspectors later determined that the permits were not required. The RSH was not routinely occupied and no station personnel were observed at the RSH with the exception of operators performing the surveillance. The operators present for the surveillance test were unaware of the fire protection issues
,
observed by the inspectors.
j The inspectors noted that BAP 1100-9, step C.6, " Cleanup of Flammable / Combustible Liquids," paragraph a., stated that " flammable or combustible liquids which are leaked or spilled shall be promptly cleaned up and not allowed to accumulate. Materials used to clean up the spill should be removed from the building." The inspectors considered the oily rags and tygon tubing in the large plastic trash can to be material used to clean up a spill. The Fire Marshal stated that there was a difference between oil soiled rags and oil soaked rags and that only oil soaked rags needed to be controlled as a transient combustible. The inspectors noted that BAP 1100-9 stated that the material used to clean up the spill should be removed from the building and did not discriminate between oil soiled and oil soaked rags. The inspectors considered the failure to remove the material used to clean up a spill an example of a violation of BAP 1100-9 and TS 6.8.1.g.
(50-454/455-98005-05a(DRP)).
Paragraph C.2.b. of BAP 1100-9 allowed exceptions to the Transient Load Permit and stated " Flammable / combustible liquid containers that do not require prior authorization are: 1) approved / original containers of five gallons or less being transported and used immediately in the plant while in attendance of plant personnel." The inspectors noted that the two containers of cleaning solution in the RSH were less than 5 gallons; however, the containers were unattended. The inspectors considered the failure to control the cleaning solution containers an example of a violation of BAP 1100-9, paragraph C.2.b and TS 6.8.1.g. (50-454/455-98005-05b(DRP)).
After the inspectors identified the cleaning solution, the licensee's PIF noted that the two containers of cleaning solution were not required to be controlled due to the category designator. The inspectors noted that the solution had a Category lll sticker on the container. Category lli was defined in BAP 1100-T8, " Table of Definitions for Flammable and Combustible Terms," Revision 1, under combustible liquid as any liquid having a flashpoint at of above 140 degrees Fahrenheit. Therefore, the inspector concluded that l
the cleaning solution was required to be controlled in accordance with BAP 1100-9.
Paragraph C.2.c of BAP 1100-9 stated that " aerosol containers should be transported and used in quantities not to exceed the amount needed for a specificjob. These containers
r l
-
---_- _ _
_ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - - _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ - _ _ _ _ - _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
., o
,
I should not be left unattended in the plant at any time. Storage in a Fire Marshal approved Flammable Liquids cabinet per paragraph C.5 is acceptable." The aerosol cans the inspectors observed were unattended and not in a storage cabinet. The inspectors considered the unattended aerosol cans an example of a violation of BAP 1100-9, paragraph C.2.c and TS 6.8.1.g. (50-454/455-98005-05c(DRP)).
On January 27,1998, during a routine auxiliary building inspection, the inspectors noted two aerosol cans of degreaser and 2 cans of anti-seize lubricant in the work area of the
'
18 SX pump. The work area was unattended by any licensee personnel. The inspectors noted the requirements of BAP 1100-9, paragraphs C.2.b. and c., as described above and discussed the issue with the Fire Marshal. The Fire Marshal stated that phases that referenced " unattended" and "while in attendance of plant personnel" did not include j
,
!
break and lunch periods. The inspectors noted that the procedure did not make a reference to periods of time combustible material could be left unattended. The inspectors noted severallocations in BAP 1100-7 and BAP 1100-9 that discussed l
unattended combustible materials and none of them defined " unattended." The l
inspectors were concemed that fire protection procedures were interpreted differently
,
than the, actual procedure.
!
The inspectors originally considered the observations on January 27,1998, minor i
violations, However, based on the observations at the RSH and procedure interpretation l
concerns, the inspectors concluded that the two cans of aerosol degreaser were additional examples of a violation of BAP 1100-9, Step C.2.c
(50-454/455-98005-05c(DRP)), and the two cans of anti-seize lubricant were examples of
'
a violation of BAP 1100-9, step C.2.b. (50-454/455-98005-05b(DRP)).
During a routine inspection of the auxiliary building on January 30,1998, the inspectors i
found an approximately %-gallon can containing oilleft unattended in the Spent Fuel Pool (SFP) pump room and notified the Fire Marshal. After reviewing the circumstances, the Fire Marshal informed the *pectors that the oil can had been left in the SFP pump room by operations personnel ar.J that the shift manager had been notified to have the oil can l
removed.
l l
As described above, paragraph C.2.b. of BAP 1100-9 allowed exceptions to the Transient i
Load Permit. The inspectors noted that the oil can was less than 5 gallons; however, the container was unattended. The inspectors considered the failure to control the oil can another example of a violation of BAP 1100-9, paragraph C.2.b and TS 6.8.1.g.
(50-454/455-98005-05b(DRP)).
l At the end of the inspection period, the licensee had started a review of the fire protection procedures. The review was to identify areas were revisions were required as well as areas where the standards needed to be enforced. r) raft procedure revisions had been completed at the end of the inspection period, c.
Conclusion Based on the discussions with the Fire Marshal and the examples of failing to adhere to procedures, the inspectors concluded that the transient material control procedures had been interpreted to allow various practices that were not in accordance with the procedures. The inspectors were concemed that fire protection procedures were not
I
- - ___ _ _ __- _ _ - _ _ _ _ __ _ -_-_-_ _ _ _ _-__-___ - _____ __- -______________- __ _ _____ _-_______ - _- _ - ____ - __ -__ ____ _ _
l
.*
.
i i
l being followed due to the number of verbalinterpretations that the inspectors identified.
Three violations with multiple examples were identified.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 23,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
L
4
_
_ __ _ ____ _ _____ _
___-____
__ - ______ _ _
_ _ - _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _
I
'
..
PARTIAL LIST OF PERSONS CONTACTED j
Licensee i
K. Kofron, Byron Station Manager
'
J. Bauer, Health Physics Supervisor D. Brindle, Regulatory Assurance Supervisor E. Campbell, Maintenance Superintendent T. Gierich, Operations Manager T. Schuster, Manager of Quality & Safety Assessment M. Snow, Work Control Superintendent B. Kouba, Engineering Manager I
I
!
'
i
)
i
..
..
.'
.
INSF ECTION PROCEDURES USED IP 50001:
Steam Generator Replacement inspection IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support IP 92700:. Onsite Followup of Writterr Report of Non-Routine Events at Power Reactor Facilities IP 92901:
Followup Operations IP 92902:
Followup Maintenance IP 92903:
Followup Engineering IP 92904:
Followup Plant Support ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-454/455-98005-01a VIO Failure to retum equipment to service es required by OOS program 50-454/455-98005-01b VIO Failure to submit ER prior to installing gasket in 1B SX Pump 50-454/455-98005-02 VIO NSWP-A-03 inadequate to prevent material intrusion in CS system 50-454/455-98005-03 NCV Failure to track breaker position on maintenance alteration line-up stu.et 50-454/455-98005-04 VIO Failure to perform safety evaluation for venting CV system l
to VCT 50-454/455-98005-05a VIO Failure to remove material used to clean up oil spill 50-454/455-98005-05b VIO Flammable / Combustible liquid containers unattended in the l.
plant 50-454/455-98005-05c VIO Aerosol cens unattended in the plant Closed 50-454/455-95007-01 URI Lack of documentation in electrical fuse control program 50-454/455 96003-02 VIO Controlled leakage TS violation 50-454/455-96005-01 VIO Unexpected dilution of Unit 1 50-454/455-96007-02 VIO Inadequate procedure to supply SX to 2A CV pump lube oil cooler 50-454-95-010 LER Chemistry sample not representative 50-454/455-95009-01 VIO Failure to have integrated leak test on systems outside containment 50-454/455 96003-07 URI Potentialinoperable SX due to strainer backwash valves 50-454/455-97022-03 URI Failure to perform safety evaluation prior to venting 2B CV pump to VCT 50-454/455-98005-03 NCV Failure to track breaker position on maintenance alteration line-up sheet.
_ _ _ _ _ _ - - _ _ _ - _. _ _ _ _ _ _
_
r
- - - -
- --
- - - - -
- ~ - - ------- --- - - - - - - -
- - - ' - - - - - - - - - - - - - -
, 0*
LIST OF ACRONYMS USED l
AF Auxiliary Feedwater ASME American Society of Mechanical Engineers BAP Byron Administrative Procedure BAR Byron Annunciator Response BOP Byron Operating Procedure CAR Corrective Action Record CNOO Chief Nuclear Operating Officer CS Containment Spray CV Chemical and Volume Control DG Diesel Generator DRP Division of Reactor Projects DRS Division of Reactor Safety ECCS Emergency Core Cooling System ER Engineering Request FME Foreign Material Exclusion GWPS Gaseous Waste Processing System
)
INPO Institute for Nuclear Power Operations LCO Limiting Condition for Operation LCOAR Limiting Condition for Operation Action Requirement LER Licensee Event Report LOOP Loss of Offsite Power MRM Management Review Meeting MOV Motor Operated Valve NLO Nonlicensed Operator NOC.
Nuclear Oversight Committee NOD Nuclear Operations Division NSO Nuclear Station Operator NSWP Nuclear Station Work Procedure OOS Out-of-Service PDR Public Document Room PlF Problem identification Form PWR Pressurized Water Reactor Q&SA Quality and Safety Assessment RCS Reactor Coolant System RH Residual Heat Removal RP Radiological Protection RSH River Screen House SCRE Shift Control Room Engineer SFP Spent Fuel Pool SPP Special Plant Procedure SRO Senior Reactor Operator SSPS Solid State Protection System SX=
Essential Service Water System TS Technical Specification UFSAR Updated Final Safety Analysis Report
VCT Volume Control Tank i
'
WR Work Request l
i