ML043100605
| ML043100605 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/05/2004 |
| From: | William Jones NRC/RGN-IV/DRP |
| To: | Parrish J Energy Northwest |
| References | |
| EA-04-0192 IR-04-004 | |
| Download: ML043100605 (46) | |
See also: IR 05000397/2004004
Text
November 5, 2004
EA-04-0192
J. V. Parrish (Mail Drop 1023)
Chief Executive Officer
Energy Northwest
P.O. Box 968
Richland, WA 99352-0968
SUBJECT:
COLUMBIA GENERATING STATION - NRC INTEGRATED INSPECTION
REPORT 05000397/2004004
Dear Mr. Parrish:
On September 23, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Columbia Generating Station. The enclosed inspection report documents the
inspection findings which were discussed on September 30, 2004, with Mr. Webring and other
members of your staff.
The inspections examined activities conducted under your license as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report documents one NRC identified finding, three self-revealing findings, and a finding
with both an NRC and a self-revealing examples that were of very low safety significance
(Green). Three of these findings were determined to involve violations of NRC requirements.
However, because of the very low safety significance and because they are entered into your
corrective action program, the NRC is treating these three findings as non-cited violations
(NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest these
NCVs, you should provide a response within 30 days of the date of this inspection report, with
the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control
Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV, 611
Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident
inspector at the Columbia Generating Station.
Energy Northwest
-2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document
system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
William B. Jones, Chief
Project Branch E
Division of Reactor Projects
Docket: 50-397
License: NPF-21
Enclosure:
NRC Inspection Report 05000397/2004004
cc w/enclosure:
W. Scott Oxenford (Mail Drop PE04)
Vice President, Nuclear Generation
Energy Northwest
P.O. Box 968
Richland, WA 99352-0968
Albert E. Mouncer (Mail Drop PE01)
Vice President, Corporate Services/
General Counsel/CFO
Energy Northwest
P.O. Box 968
Richland, WA 99352-0968
Chairman
Energy Facility Site Evaluation Council
P.O. Box 43172
Olympia, WA 98504-3172
Douglas W. Coleman (Mail Drop PE20)
Manager, Regulatory Programs
Energy Northwest
P.O. Box 968
Richland, WA 99352-0968
Energy Northwest
-3-
Gregory V. Cullen (Mail Drop PE20)
Supervisor, Licensing
Energy Northwest
P.O. Box 968
Richland, WA 99352-0968
Chairman
Benton County Board of Commissioners
P.O. Box 190
Prosser, WA 99350-0190
Dale K. Atkinson (Mail Drop PE08)
Vice President, Technical Services
Energy Northwest
P.O. Box 968
Richland, WA 99352-0968
Thomas C. Poindexter, Esq.
Winston & Strawn
1400 L Street, N.W.
Washington, DC 20005-3502
Bob Nichols
Executive Policy Division
Office of the Governor
P.O. Box 43113
Olympia, WA 98504-3113
Lynn Albin, Radiation Physicist
Washington State Department of Health
P.O. Box 7827
Olympia, WA 98504-7827
Technical Services Branch Chief
FEMA Region X
Federal Regional Center
130 228th Street, S.W.
Bothell, WA 98021-9796
Energy Northwest
-4-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (ZKD)
Resident Inspector (RBC1)
Branch Chief, DRP/E (WBJ)
Senior Project Engineer, DRP/E (VGG)
Acting Team Leader, DRP/TSS (RVA)
RITS Coordinator (KEG)
Matt Mitchell, OEDO RIV Coordinator (MAM4)
Columbia Site Secretary (LEF1)
Dale Thatcher (DFT)
W. A. Maier, RSLO (WAM)
NSIR/EPPO (JDA1)
ADAMS: W Yes
G No Initials: _WBJ__
W Publicly Available G Non-Publicly Available
G Sensitive W Non-Sensitive
R:\\_COL\\2004\\COL2004-04RP-ZKD.wpd
RIV:SRI:DRP/E
RIV:SRI:DRP/E
RIV:SPE:DRP/E
C:DRS/EB
ZK Dunham
RBCohen
VGGaddy
JAClark
T-WBJ
T-WBJ
E-WBJ
LEE For
11/4/04
11/4/04
11/4/04
11/4/04
C:DRS/OB
C:DRS/PSB
C:DRS/PEB
C:DRP/E
TGody
MShannon
LJSmith
WBJones
/RA/
/RA/
E-WBJ
/RA/
11/5/04
11/4/04
11/4/04
11/5/04
OFFICIAL RECORD COPY D=Discussed T=Telephone E=E-mail F=Fax
Enclosure
ENCLOSURE
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
50-397
License:
Report:
Licensee:
Energy Northwest
Facility:
Columbia Generating Station
Location:
Richland, Washington
Dates:
June 24 through September 23, 2004
Inspectors:
Z. Dunham, Senior Resident Inspector, Project Branch E, DRP
G. Replogle, Senior Resident Inspector, Project Branch E, DRP
R. Cohen, Resident Inspector, Project Branch E, DRP
G. Larkin, Resident Inspector, Project Branch E, DRP
R. Lantz, Senior Emergency Preparedness Inspector
M. Sitek, Resident Inspector, Project Branch C, DRP
T. McKernon, Senior Operations Engineer, Operations Branch
D. Stearns, Project Engineer, Project Branch E, DRP
P. Elkmann, Emergency Preparedness Inspector
L. Ricketson, Senior Health Physicist, Plant Support Branch
L. Ellershaw, Senior Engineering Inspector, Engineering Branch
Approved By:
W. B. Jones, Chief, Project Branch E, Division of Reactor Projects
ATTACHMENT:
Supplemental Information
Enclosure
CONTENTS
PAGE
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REACTOR SAFETY
1R04
Equipment Alignments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R05
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R07
Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1R11
Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1R13
Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . . 6
1R15
Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R16
Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R19
Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R20
Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R22
Surveillance Testing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
1R23
Temporary Plant Modifications
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1EP1 Exercise Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
OTHER ACTIVITIES
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
4OA4 Crosscutting Aspects of Findings
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA5 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
4OA6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
4OA7 Licensee Identified Vioations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
ATTACHMENT: SUPPLEMENTAL INFORMATION
Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
Items Opened and Closed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
Partial List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
Enclosure
SUMMARY OF FINDINGS
IR05000397/2004004; 6/24/2004 - 9/23/2004; Columbia Generating Station. Surveillance
Testing and Event Followup.
The report covered a 13-week period of inspection by the resident inspectors, emergency
preparedness inspectors, a health physicist inspector, an operations inspector, and an
engineering inspector. Three Green noncited violations, two Green findings, and two
unresolved item were identified. The significance of most findings is indicated by their color
(Green, White, Yellow, Red) using Inspection Manual Chapter 0609, Significance
Determination Process. Findings for which the significance determination process does not
apply may be Green or be assigned a severity level after NRC management review. The
NRCs program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A.
NRC Identified and Self-Revealing Findings
Cornerstone: Initiating Events
Green. A self-revealing finding associated with control room operators failure to
adequately monitor condenser hotwell level occurred when hotwell level was
established high in the indicating range and above the hotwell level high level
alarm. This condition resulted in the associated hotwell level high level
annunciator being locked in and was effectively out of service. A manual reactor trip was initiated when the hotwell level excursion resulted in the loss of the only
operating reactor feedwater pump.
This finding is greater than minor because it was a human performance issue
which impacted the initiating events cornerstone objective. Specifically,
adequate compensatory actions were not put in place to address the hotwell
level high level annunciator. This finding had crosscutting aspects in the area of
human performance in that adequate monitoring of hotwell level was not
implemented which contributed to the reactor scram. A Phase 2 evaluation was
performed in accordance with Manual Chapter 0609, Significance Determination
Process, based on the finding contributing to both the likelihood of a reactor trip
and that mitigation functions would not be available. The Phase 2 review was
performed using the Columbia Generating Station site specific worksheets. A
senior reactor analyst reviewed the Phase 2 results and performed a limited
Phase 3 review. The senior reactor analyst considered the limited time the plant
was at a low power level and adjusted the time in power operations to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
The finding was determined to be of low safety significance. Corrective actions
included revising hotwell alarm response and operating procedures to preclude
operation of the hotwell at levels above the high level alarm (Section 4OA3.2)
Green. A self-revealing finding occurred when an equipment operator failed to
follow a clearance order instruction when filling and venting a condensate heat
exchanger. This action resulted in a low suction trip of a reactor feedwater
pump, the loss of reactor feedwater and a subsequent manual reactor scram.
-2-
Enclosure
This finding is greater than minor because it was a human performance issue
which impacted the initiating events cornerstone objective to limit the likelihood
of those events that upset plant stability and challenge critical safety functions.
This finding had crosscutting aspects in the area of human performance in that
adequate pretask briefings were not performed for the the operator placing the
feedheater back into service. A Phase 2 evaluation was performed in
accordance with Manual Chapter 0609, Significance Determination Process,
based on the finding contributing to both the likelihood of a reactor trip and that
mitigation functions would not be available. The Phase 2 review was performed
using the Columbia Generating Station site specific worksheets. A senior
reactor analyst reviewed the Phase 2 results and performed a limited Phase 3
review. The senior reactor analyst considered the limited time the plant was at a
low power level and adjusted the time in power operations to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. The
finding was determined to be of low safety significance. Corrective actions
included temporary senior reactor operator oversight of all pretask briefings and
remedial training for the individuals involved (Section 4OA3.3).
Cornerstone: Mitigating Systems
Green. A self-revealing noncited violation of Technical Specification 5.4.1.a
occurred when operators failed to return a nuclear power range instrument to
service after bypassing the instrument for a gain adjustment in accordance with
a surveillance procedure. This resulted in the instrument being left out of service
for an additional seven hours after it was available for use. There were
indications readily available to the control room staff to identify the out of service
component earlier than when it was finally identified. This finding had cross
cutting aspects in the area of human performance in that the nuclear power
range instrument was not appropriately returned to service and several
opportunities were available, including a shift turnover to identify the condition.
Corrective actions included returning the instrument to service and revising the
frequency of panel walkdowns in the control room to ensure a more thorough
examination of plant indications.
This finding is greater than minor because it involved a configuration control
issue which impacted the mitigating systems cornerstone objective to ensure the
reliability of systems that respond to initiating events to prevent undesirable
consequences. The issue was of very low safety significance (Green) because
the finding did not result in the loss of function of a safety system or represent an
actual loss of a safety function of a single train for greater than its Technical
Specification allowed outage time (Section 1R22).
Cornerstone: Emergency Preparedness
-3-
Enclosure
Green. The inspectors identified a noncited violation for Energy Northwests
failure to activate the Emergency Response Data System within 60 minutes in
accordance with 10 CFR 50.72(a)(4) after declaring an Alert on July 30, 2004.
This finding had cross cutting aspects in the area of human performance in that
Emergency Response Data System was not initiated as required within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The finding is greater than minor because it was associated with an actual event
response performance deficiency that affected the emergency preparedness
cornerstone objective to ensure that Energy Northwest is capable of
implementing adequate measures to protect the health and safety of the public in
the event of a radiological emergency. By not activating Emergency Response
Data System within the required time, Energy Northwest hindered the NRCs
ability to verify plant conditions to ensure the appropriateness of any licensee
recommended emergency response actions. The finding was of very low safety
significance because although the finding was associated with an
implementation problem during an actual Alert declaration, the failure to comply
with the requirements of 10 CFR 50.72(a)(4) did not constitute a failure to
implement a risk significant planning standard. Corrective actions included
assigning additional on-shift personnel the responsibility of activating Emergency
Response Data System to ensure that time requirements are met
(Section 4OA3.1)
Cornerstone: Occupational Radiation Safety
Green. The inspector reviewed two examples of a noncited violation of
10 CFR 20.1501(a) because Energy Northwest failed to evaluate radiological
conditions. One example was self-revealing; one was NRC-identified. In the first
example, Energy Northwest failed to evaluate the changing radiological
conditions during gasket replacement on Reactor Water Clean Up Pump 1B. As
a result, four workers were internally and externally contaminated. In the second
example, also involving the reactor water clean up system, Energy Northwest
failed to survey airborne radioactivity before or during work activities on a system
pump despite the potential for steam leaks. The findings were entered into
Energy Northwests corrective action program as Condition Reports 2-04-01975
(PER 20400759) and 2-04-04966.
The finding was more than minor because it was associated with one of the
cornerstone attributes (exposure control) and affected the associated
cornerstone objective because it resulted in decreased licensee awareness of
possible radiological hazards. The occurrence involved individual workers
unplanned, unintended doses or potential of such a dose resulting from actions
contrary to NRC regulations that could have been significantly greater as a result
of a single minor, reasonable alteration of the circumstances. Using the
Occupational Radiation Safety Significance Determination Process, the inspector
determined the finding was of very low safety significance because it was not (1)
-4-
Enclosure
an ALARA finding, (2) an overexposure, (3) a significant potential for
overexposure, or (4) a loss of ability to assess dose. This finding also had
crosscutting aspects associated with human performance (Section 2OS2).
B.
Licensee Identified Violations
Violations of very low safety significance which were identified by Energy Northwest
have been reviewed by the inspectors. Corrective actions taken or planned by Energy
Northwest have been entered into their corrective action program. These violations and
corrective action tracking numbers are listed in Section 4OA7 of this report.
Enclosure
REPORT DETAILS
Summary of Plant Status:
The inspection period began with Columbia Generating Station at 100 percent power. The
plant was maintained at essentially 100 percent power for the entire inspection period with the
following exceptions: July 30, 2004, the plant automatically tripped on high reactor pressure
vessel pressure due to a failed main turbine governor valve control circuit card. The plant
remained shutdown and entered Forced Outage 04-01 to perform repairs on two main steam
isolation valves; August 14, 2004, the plant was started up and entered the power range;
August 15, 2004, the plant was manually tripped due to a loss of feedwater which occurred
when the main condenser hotwell overflowed; August 16, 2004, the plant was started up and
entered the power range; August 17, 2004, the plant was manually tripped due to a loss of
feedwater which occurred when an equipment operator failed to properly fill and vent a
condensate heater; August 20, 2004, the plant was started up and entered the power range
and exited Forced Outage 04-01; August 24, 2004, the plant achieved 100 percent power. The
plant was maintained at essentially 100 percent power for the rest of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04
Equipment Alignments (71111.04)
.1
Quarterly Partial Equipment Alignments
a.
Inspection Scope
The inspectors completed three partial system walkdowns of safety-related systems
during the inspection period. The inspectors reviewed system drawings, the Final
Safety Analysis Report, Technical Specifications, and operating procedures to establish
the proper equipment alignment to ensure system operability.
Residual Heat Removal (RHR) System Train A: On August 12, 2004, the
inspectors walked down the mechanical and electrical alignment of the RHR
system Train A while Train B was inservice providing decay heat removal during
a forced outage. The inspectors reviewed the alignment of critical system
components using Procedure SOP-RHR-SDC, RHR Shutdown Cooling,
Revision 4.
Emergency Diesel Generator (EDG) Train B: On September 8, 2004, the
inspector walked down the mechanical and electrical alignments of the EDG
Train B while the EDG Train A was out of service for planned surveillance
testing. The inspectors reviewed the alignment of critical system components
using Procedure SOP-DG2-STBY, Emergency Diesel Generator (Div 2) Standby
Lineup, Revision 3, as criteria for this inspection.
-2-
Enclosure
Reactor Core Isolation Cooling (RCIC): On September 13, 2004, the inspectors
performed one partial walk down of accessible portions of the RCIC system to
evaluate the correct alignment of mechanical components. The inspectors
utilized facility drawings, procedures and alignment checklists to verify the
correct system alignment. The inspectors then compared the as-found condition
of the system to verify that it could perform it safety function. The inspectors
also evaluated the material condition of the system.
b.
Findings
No findings of significance were identified.
.2
Complete System Walkdown (Semiannual)
a.
Inspection Scope
On August 31, 2004, the inspectors performed a walkdown of accessible portions of the
Standby Service Water (SW) System Train A, while the system was in service to verify
operational status and material condition of the system and its components. The
inspectors reviewed system drawing M-524, "Flow Diagram Standby Service Water
System," Revision 104, to verified proper electrical and mechanical system lineup. The
inspectors also reviewed outstanding maintenance work orders and assessed
operability and conformance with licensing requirements and commitments. The
inspectors evaluated Energy Northwests corrective measures to address related
conditions adverse to quality to verify that corrective measures were timely and
adequate. The inspectors reviewed the following documents during the inspection:
Final Safety Analysis Report Chapter 9.2, Water Systems
Technical Specification 3.7.1, SW System and Ultimate Heat Sink (UHS),
Amendment No. 169
Drawing M-524, "Flow Diagram Standby Service Water System" Revision 104
PER [Proble Evaluation Request] Resolution 203-0234, potential adverse trend
on SW flow indicators.
PER Resolution 203-0589, SW-PI-40 (HPCS [High Pressure Core Stray] SW
PAM instrumentation) is inoperable for greater than 30 days.
PER Resolution 203-1202, UT inspection reveals two areas of small wall loss in
the SW piping downstream of SW-RO-2B.
PER Resolution 203-1616, several deficiencies noted on 18" SW (22)-2 SW A
return Line between SWPH A and the SW B Spray Pond.
PER Resolution 203-1348, UT inspection revealed several small areas with
thickness below ASME Code requirements in an area where a pin hole leak was
discovered, downstream of SW-RO-2A.
PER Resolution 203-2983, during a check of SW flows per the values of OSP-
SW-M 102, less than the minimum required flow was identified.
-3-
Enclosure
PER Resolution 203-2989, current practice of aligning SW to CCH-CR-1B after
performing OSP-SW-M 102 seems to affect SW B system flow balance more
than previously thought.
PER Resolution 203-3123, recent low flow PERS pose a question regarding SW
system reliability.
PER Resolution 203-3180, scheduled UT measurement of piping downstream of
SW shows continued cavitation-induced wall loss.
PER Resolution 203-3294, identified SW flow below the minimum for operability
to CAC-HR-1B.
PER Resolution 203-3427, SW-LI-1B and SW-LI-1BR are indicating
approximately 1.5 feet higher than actual spray pond level.
PER Resolution 203-4101, unplanned Technical Specification action statement
entry due to low service water flow on CAC MCC room cooler.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection (71111.05)
.1
Quarterly Walkdowns
a.
Inspection Scope
The inspectors performed walkdowns of eight fire protection areas to verify operational
status and material condition of fire detection and mitigation systems, passive fire
barriers and fire suppression equipment. The inspectors reviewed Energy Northwests
implementation of controls for combustible materials and ignition sources in selected fire
protection zones. The inspectors compared observed plant conditions against
descriptions and commitments described in the Final Safety Analysis Report,
Section 9.5.1, Fire Protection System, and Appendix F, Fire Protection Evaluation.
The fire areas inspected were:
Fire Area RC-10; Main Control Room; July 15, 2004
Remote Shutdown Room; July 15, 2004
Fire Area DG-1; High Pressure Core Spray Diesel Generator; August 11, 2004
Fire Area DG-2; Diesel Generator 1A; August 10, 2004
Fire Area DG-3; Diesel Generator 1B; August 10, 2004
Fire Area R-4; Residual Heat Removal Pump 2B Room; August 18, 2004
Fire Area R-5; Residual Heat Removal Pump 2A Room; August 18, 2004
Fire Area R-7; Residual Heat Removal Pump 2C Room; August 18, 2004
b.
Findings
No findings of significance were identified.
-4-
Enclosure
1R07
Heat Sink Performance (71111.07)
a.
Inspection Scope
On July 16, 2004, the inspectors analyzed one evaluation associated with the HPCS
EDG cooling water heat exchanger thermal performance which was tested on June 23,
2004. The inspectors reviewed the test data to ensure that test acceptance criteria were
appropriate and considered differences between test conditions and design conditions.
The inspectors also considered Energy Northwests incorporation of instrument
inaccuracies into the test program. Lastly, the inspectors performed checks of selected
test results through independent calculation to ensure that the heat exchanger was
capable of removing its design heat load. The inspectors referenced Procedure PPM
8.4.63, Thermal Performance Monitoring of DCW-HX-1C, dated June 23, 2004.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification (71111.11)
a.
Inspection Scope
On July 19, 2004, the inspectors observed one licensed operator requalification training
exam as operators participated in an evaluated scenario on the plant simulator. The
inspectors evaluated the crews performance in terms of command, control, and
communications and procedure usage. The inspectors also observed Energy
Northwests evaluation of crew performance to ensure that performance deficiencies
were appropriately discussed and evaluated. Simulator fidelity was also reviewed by the
inspectors.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Effectiveness (71111.12)
.1
Routine Maintenance Effectiveness Evaluations
a.
Inspection Scope
The inspectors performed one in-office review of maintenance rule related issues and/or
safety related systems to evaluate Energy Northwests assessment of availability and
reliability of risk-significant structures, systems and components.
-5-
Enclosure
Performance Evaluation Report (PER) 204-0628; E-IN-3A was running, for
testing, in parallel with E-IN-3B which could cause an overload condition of the
Division 1 125 VDC system; March 10, 2004
The inspectors utilized the following documents for this inspection:
TI 4.22, Maintenance Rule Program, June 19, 2001
Columbia Generating Station Maintenance Rule Scoping Matrix,
October 30, 2003
NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of
Maintenance at Nuclear Power Plants, Revision 2
Procedure 1.5.11; Maintenance Rule Program, Revision 6
b.
Findings
No findings of significance were identified.
.2
Biennial Maintenance Rule Implementation Inspection
a.
Inspection Scope
Periodic Evaluation Reviews
The inspectors reviewed Energy Northwest's last four biannual periodic assessments,
Maintenance Rule Program Biannual Period Status Report, each covering a 6-month
period beginning with the July through December 2002 report, and ending with the
January through June 2004 report. These reports documented the results of Energy
Northwests assessment of the Maintenance Rule Program based on performance
monitoring, condition monitoring, and preventive maintenance. In addition, the
inspectors reviewed Energy Northwests overall implementation of the Maintenance
Rule, including their Maintenance Rule Scope, (a)(1) determinations, performance
criteria, program definitions, use of industry operating experience, and Maintenance
Rule related self assessments. With respect to those structures, systems, or
components identified as being in an (a)(1) status, the inspectors verified the
establishment of appropriate goals, corrective actions and the impact of risk monitoring.
The inspectors reviewed the conclusions reached by Energy Northwest with regard to
the balance of reliability and unavailability for specific maintenance rule functions. The
inspectors selected the following systems that had either been placed in (a)(1) status, or
had recently been returned to (a)(2) status for a detailed review:
SW-SYS-A and -B [both in (a)(1)]
DG-SYS-A [returned to (a)(2) from (a)(1)]
RPS-MG-1 [returned to (a)(2) from (a)(1)]
RHR-SYS-A [in (a)(1)]
RCIC-SYS-1 [in (a)(1)]
-6-
Enclosure
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
The inspectors selected four samples of planned and emergent maintenance tasks for
evaluation. The evaluation consisted of reviewing Energy Northwests assessment of
plant risk for the activity, risk management and review of compensatory measures,
where appropriate, and reviewing plant status to ensure that other equipment
deficiencies did not adversely impact the planned risk assessment. The inspectors
sample included:
Main steam leakage control Train A out of service coincident with EDG Train B
diesel generator and Train B RHR system; June 30, 2004
Main steam isolation Valve MS-V-28D and MS-V-22D repairs; August 9, 2004
Feedwater containment isolation Valve RFW-V-65A emergent work;
August 27, 2004
RCIC maintenance outage coincident with standby gas treatment Train A
maintenance; September 1, 2004
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors reviewed three operability evaluations to evaluate Energy Northwests
assessment of operability for degraded or nonconforming equipment performance. The
inspectors reviewed the Final Safety Analysis Report, Technical Specifications,
applicable system drawings and design specifications, and associated corrective action
documents to determine if Energy Northwest had appropriately evaluated operability.
PER 204-0935, Several discrepancies noted on the positions of D/G room
ventilation dampers; July 19, 2004
CR 2-04-04511, Pressurization of Train B RHR Low Pressure Piping During
Reactor Heat-up; August 16, 2004
-7-
Enclosure
CR 2-04-01508, In 1995 an incorrect stem diameter was applied during
diagnostic testing of Valve MSLC-V-1D. Actual thrust/torque is greater than
recorded; identified by licensee on April 15, 2004; reviewed on
September 21, 2004
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (71111.16)
a.
Inspection Scope
The inspectors reviewed operator workarounds to ascertain the cumulative effects on
reliability, availability, and potential for misoperation of a system. The review also
included an assessment of the cumulative operator workarounds, operator burdens, and
whether they could affect multiple mitigating systems and whether operators were able
to respond in a correct and timely manner to accidents and plant transients.
b.
Findings
No findings of significance were identified.
1R19
Postmaintenance Testing (71111.19)
a.
Inspection Scope
The inspectors observed or completed an in-office review of six postmaintenance tests.
The inspectors evaluated the scope of the maintenance activity, reviewed design basis
information, and reviewed technical specifications to verify that each test adequately
demonstrated equipment operability. The inspection samples included:
Work Order 01082365; RHR-FIS-10B Replacement; June 30, 2004
Work Order 01084406; MS-V-67D Valve Replacement; August 12, 2004;
reviewed on August 16, 2004
Work Order 01077279; MS-V-28D Disassemble and Reassemble;
August 12, 2004
Work Order 01060822; MS-V-22D Disassemble and Reassemble;
August 13, 2004
Work Order 01062381; Replace IRM-DET-2F; August 18, 2004
-8-
Enclosure
Work Order 01079061; RCIC-P-1 Change Bearing Housing Oil;
August 31, 2004
b.
Findings
No findings of significance were identified.
1R20
Refueling and Outage Activities (71111.20)
a.
Inspection Scope
Forced Outage 04-01 began on July 30, 2004, and ended on August 24, 2004. During
the outage, the inspectors observed reactor scram recovery, cooldown, startup, and
maintenance activities to verify that Energy Northwest maintained the plant capabilities
within the applicable Technical Specification requirements and within the scope of the
outage risk plan. Specific activities evaluated included:
Reactor Water Inventory Controls - verified that flow paths, equipment
configurations, and alternative means for inventory addition were appropriate to
prevent inventory loss.
Reactivity Controls - ensured compliance with Technical Specifications and
verified that activities, which could affect reactivity, were reviewed for proper
control within the outage risk plan.
Monitored Shutdown Cooling System - verified that operating parameters were
established and maintained within the required range.
Reactor Coolant System Instrumentation Indication - verified that reactor coolant
system pressure, level, and temperature instrumentation were installed and
configured to provide accurate indication.
Heatup and Startup Activities - ensured that Technical Specifications and
administrative procedure prerequisites for mode changes were met prior to
changing modes or plant configurations. Included an inspection of the drywell
prior to drywell closeout.
Electrical Power - verified that electrical power systems were available to ensure
compliance with Technical Specifications and the outage risk plan.
b.
Findings
No findings of significance were identified.
-9-
Enclosure
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed the performance and/or reviewed the results of the five
surveillance tests listed below. Of the five surveillance tests, two were in-service tests of
risk significant components. The inspectors reviewed Technical Specification, Final
Safety Analysis Report, and applicable Energy Northwest procedures to determine if the
surveillance tests demonstrated that the tested components were capable of performing
their intended design functions. Additionally, the inspectors evaluated significant test
attributes such as potential preconditioning, clear acceptance criteria, accuracy and
range of test equipment, procedure adherence, and completion and acceptability of test
data.
Procedure OSP-RHR/IST-Q704; Emergency Core Cooling Systems;
Revision 14; July 28, 2004
Procedure TSP-MSIV-B801; Train D MSIV Leak Rate Testing; Revision 1;
August 13, 2004
Procedure ISP-LPCS/RHR-Q901; RHR A & LPCS Discharge Pressure - ADS
Trip System A Permissive (By K10A Relay) - CFT/CC; Revision 7; July 28, 2004
Procedure TSP-APRM-C301; APRM and Core Thermal Power Channel
Calibration Check; Revision 4; August 24, 2004
Procedure OSP-LPCS/IST-Q702; LPCS System Operability Test; Revision 12;
August 29, 2004
b.
Findings
Introduction. A Green self revealing NCV occurred as a result of Energy Northwests
failure to follow a surveillance test procedure and return Average Power Range
Monitor (APRM) B to service. This was identified as a violation of Technical Specification 5.4.1.a.
Description. On August 24, 2004, control room operators performed Procedure TSP-
APRM-C301, APRM and Core Thermal Power Channel Calibration Check, Revision 4,
to perform a gain adjustment on APRM B. The APRM was bypassed at 1600 per TSP-
APRM-C301, Attachment 9.1, Step 3, to facilitate the gain adjustment. Following the
gain adjustment, the operators failed to return APRM B to service by unbypassing the
instrument per Step 8 of Attachment 9.1. Procedure TSP-APRM-C301 was
subsequently reviewed by a senior reactor operator and was closed out at 1751. At
0100 the next day, during a control board walkdown in preparation for a gain adjustment
on a different channel APRM, the reactor operator noted that APRM B was bypassed.
APRM B was then returned to service. During the time that APRM B was inadvertently
-10-
Enclosure
bypassed, APRM D and APRM F were operable and would have performed the required
Reactor Protection System (RPS) B trip functions associated with those instruments.
The inspectors noted the following two performance issues which had human
performance crosscutting aspects:
1.
Operators failed to identify the APRM was in bypass following the conduct of the
surveillance activity and during the shift turnover. Specifically, while APRM B
was out of service, Energy Northwest underwent a control room shift change at
6:00 p.m. PDT. None of the control room staff noted that APRM B was
bypassed during the shift turnover. At 1:00 a.m. PDT (7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> following the shift
turnover) the bypassed instrument was identified. Means of having identified the
APRM was bypassed were: an APRM Bypass control board indicator, an
APRM Bypass indicator on the APRM B instrument drawer located in the
control room, and the control board APRM bypass control switch out of its
normal position.
2.
A senior reactor operator signed Procedure TSP-APRM-C301 for closure
indicating that he had reviewed the procedure. However, the initial block in
Attachment 9.1, indicating return to service of APRM B, was not initialed for the
period of time in question.
Analysis. Energy Northwests failure to return APRM B to service following the gain
adjustment was determined to be a performance deficiency and was more than minor
because it was a configuration control issue which impacted the mitigating systems
cornerstone objective to ensure the reliability of systems that respond to initiating events
to prevent undesirable consequences. The issue was of very low safety significance
(Green) because the finding did not result in the loss of function of a safety system and
did not represent an actual loss of a safety function of a single train for greater than its
Technical Specification allowed outage time.
Enforcement. Technical Specification 5.4.1.a required, in part, that written procedures
shall be established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation),
Appendix A, Section 8.b, required, in part, that specific procedures for calibrations
should be written to include incore flux monitor calibrations. Contrary to this
requirement on August 24, 2004, from 4:00 p.m. PDT, to August 25, 2004, at 1:00 a.m.
PDT, the control room operators failed to return APRM B to service in accordance with
Procedure TSP-APRM-C301, Attachment 9.1, Step 8, which required that the operator
be requested to unbypass the APRM. This violation is being treated as a noncited
violation, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 50-
397/04-04-01, Failure to Identify and Return to Service APRM B in a Timely Manner).
Energy Northwest documented this issue in their corrective action program in PER 204-
1056. Immediate corrective actions taken by Energy Northwest included verifying that
APRM B was in fact operable and returning the instrument to service. Other corrective
actions included changing the frequency of panel walkdowns in the control room to
ensure a more thorough examination of plant indications.
-11-
Enclosure
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
On August 18 and 19, 2004, the inspectors evaluated Energy Northwests use of
temporary lead shielding in the residual heat removal pump rooms. The inspectors
reviewed Energy Northwests technical and licensing basis impact evaluations for the
temporary shielding requests to ensure that the safety functions of the RHR system
remained unaffected. The inspectors also reviewed Procedure GEN-RPP-14, Control
of Temporary Shielding, Revision 3, to ensure that the use of the temporary shielding
was in accordance with Energy Northwests procedural requirements.
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP1 Exercise Evaluation (71114.01)
a.
Inspection Scope
The inspectors reviewed the objectives and scenario for the 2004 Biennial Emergency
Preparedness Exercise to determine if the exercise would acceptably test major
elements of the emergency plan. The scenario included seismic activity, which resulted
in steam leaks, valve malfunctions, and other broken equipment. Additional seismic
activity caused increased steam leakage and fuel damage, failure of isolation valves,
and a subsequent release of radioactivity to the environment. Energy Northwest
activated all of their emergency facilities to demonstrate their capability to implement the
The inspectors evaluated exercise performance by focusing on the risk-significant
activities of classification, notification, protective action recommendations, and
assessment of offsite dose consequences in the simulator control room and the
following emergency response facilities:
Operations Support Center
The inspectors also assessed personnel recognition of abnormal plant conditions, the
transfer of emergency responsibilities between facilities, communications, protection of
emergency workers, emergency repair capabilities, and the overall implementation of
the emergency plan to verify compliance with the requirements of 10 CFR 50.47(b),
10 CFR 50.54(q), and Appendix E to 10 CFR Part 50.
-12-
Enclosure
The inspectors attended the post-exercise critiques in each of the above emergency
response facilities to evaluate the initial licensee self-assessment of exercise
performance. The inspectors also attended the formal presentation of critique items to
plant management. The inspectors completed one sample during the inspection.
b.
Findings
No findings of significance were identified.
1EP6 Drill Evaluation (71114.06)
a.
Inspection Scope
The inspectors observed one Energy Northwest simulator evaluation on
August 16, 2004, in which the control room staff were required to make and report
emergency classifications in response to a simulated accident. The inspectors reviewed
the facility emergency plan implementing procedures (EPIPs) and Emergency Plan to
establish the criteria for the simulated emergency classifications. Additionally, the
inspectors reviewed the completed emergency action level declaration and notification
forms to verify the accuracy of the forms. Lastly, the inspectors reviewed Energy
Northwests evaluation of the drill to ensure that any performance deficiencies
associated with classification, notification, and PAR development were accurately
characterized.
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety [OS]
2OS2 ALARA Planning and Controls (71121.02)
a.
Inspection Scope
The inspectors assessed licensee performance with respect to maintaining individual
and collective radiation exposures as low as is reasonably achievable (ALARA). The
inspectors used the requirements in 10 CFR Part 20 and Energy Northwests
procedures required by Technical Specifications as criteria for determining compliance.
The inspector interviewed licensee personnel and reviewed:
Current 3-year rolling average collective exposure
An on-line maintenance work activity scheduled during the inspection period and
associated work activity exposure estimates that were likely to result in the
highest personnel collective exposures
-13-
Enclosure
Three work activities from previous work history data that resulted in the highest
personnel collective exposures
Site specific trends in collective exposures, plant historical data, and source-term
measurements
Site specific ALARA procedures.
ALARA work activity evaluations, exposure estimates, and exposure mitigation
requirements
Intended versus actual work activity doses and the reasons for any
inconsistencies
Assumptions and basis for the current annual collective exposure estimate, the
methodology for estimating work activity exposures, the intended dose outcome,
and the accuracy of dose rate and man-hour estimates
Method for adjusting exposure estimates, or replanning work, when unexpected
changes in scope or emergent work were encountered
Source-term control strategy or justifications for not pursuing such exposure
reduction initiatives
Radiation worker and radiation protection technician performance during work
activities in radiation areas, airborne radioactivity areas, or high radiation areas
Self-assessments and audits related to the ALARA program since the last
inspection
Corrective action documents related to the ALARA program and follow-up
activities such as initial problem identification, characterization, and tracking
The inspector completed 10 of the required 15 samples and 2 of the optional samples.
b.
Findings
Introduction. The inspectors reviewed two examples of a noncited, Green violation of
10 CFR 20.1501(a) resulting from Energy Northwests failure to evaluate radiological
conditions in work areas. One example was self-revealing; the other was
NRC-identified.
Description. On May 4, 2004, four individuals alarmed personnel contamination
monitors after performing a gasket replacement on reactor water clean up Pump 1B.
The workers were found to be internally and externally contaminated. Air samples
analyzed after the occurrence indicated 3 derived air concentrations of Cobalt-60.
Energy Northwests review of the occurrence stated that the airborne radioactivity was
likely caused by the drying of the upper pump cavity. It also stated that airborne
precautions were not adequately reconsidered and that the use of an airborne
-14-
Enclosure
radioactivity monitor may have provided an early indication that airborne conditions
existed. The inspector concluded that Energy Northwest had not adequately surveyed
or evaluated the changing radiological conditions and potential hazards.
On September 1, 2004, Energy Northwest again worked on reactor water clean up
Pump 1B. This time the tasks included postmaintenance testing and hot torquing. In
addition, one worker was assigned to look for steam leaks in the pump room. The
individual used a mirror to aid in the detection of a steam leak. At one point,
unexpectedly high dose rates were encountered in the pump room, and the job was
stopped by radiation protection personnel until further planning was completed. While
reviewing the work documents, the inspector determined that no airborne radioactivity
survey was conducted prior to or during the tasks conducted in the pump room.
The inspector concluded that this constituted a second example of a failure to survey
based on the following items: Energy Northwests search for steam leaks meant Energy
Northwest believed there was a potential for leaks to exist. Steam leaks from the
reactor water clean up system had the potential to cause unsafe airborne radioactivity
levels. Energy Northwests use of a mirror to find steam leaks meant that the leaks
were hard to see, unaided. Therefore, high airborne activity could have existed without
Energy Northwest knowing until a worker with a mirror identified a steam leak.
Analysis. A failure to survey was a performance deficiency. The finding was more than
minor because it was associated with one of the cornerstone attributes (exposure
control) and affected the associated cornerstone objective because it resulted in
decreased licensee awareness of possible radiological hazards. The occurrence
involved individual workers unplanned, unintended doses or potential of such a dose
resulting from actions contrary to NRC regulations that could have been significantly
greater as a result of a single minor, reasonable alteration of the circumstances, such as
higher airborne radioactivity concentrations. Using the Occupational Radiation Safety
Significance Determination Process, the inspector determined the finding was of very
low safety significance because it was not (1) an ALARA finding, (2) an overexposure,
(3) a significant potential for overexposure, or (4) a loss of ability to assess dose. This
finding also had crosscutting aspects associated with human performance in that
licensee personnel failed to implement the established survey requirements designed to
prevent excess occupational radiation exposure.
Enforcement. Pursuant to 10 CFR 20.1003, survey means an evaluation of the
radiological conditions and potential hazards incident to the production, use, transfer,
release, disposal, or presence of radioactive material or other sources of radiation.
10 CFR 20.1501 requires that each licensee make or cause to be made surveys that
may be necessary for Energy Northwest to comply with the regulations in
10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extent
of radiation levels, concentrations or quantities of radioactive materials, and the potential
radiological hazards that could be present. Energy Northwest violated this requirement
when it did not perform a survey to comply with the requirements of 10 CFR 20.1201.
Because the failures to survey were determined to be of very low safety significance and
have been entered into Energy Northwests corrective action program as Condition
Reports 2-04-01975 (PER 20400759) and 2-04-04966, this violation is being treated as
a noncited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy:
-15-
Enclosure
NCV 05000397/2004004-02, Two Examples of Failure to survey.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1
Mitigating Systems Cornerstone
a.
Inspection Scope
The inspectors assessed the accuracy of the two performance indicators listed below.
The inspectors compared the data with operator logs, equipment out of service logs,
and corrective action documents for the last four quarters. The inspectors verified that
Energy Northwest calculated performance indicators in accordance with NEI 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 2.
Safety System Unavailability - BWR High Pressure Coolant Injection System
Safety System Unavailability - Residual Heat Removal System
b.
Findings
No findings of significance were identified.
.2
Emergency Preparedness Cornerstone:
a.
Inspection Scope
The inspectors sampled submittals for the performance indicators listed below for the
period from October 1, 2003, through June 30, 2004. The definitions and guidance of
Nuclear Engineering Institute NEI 99-02, Regulatory Assessment Indicator Guideline,
Revision 2, were used to verify Energy Northwests basis for reporting each data
element in order to verify the accuracy of performance indicator data reported during the
assessment period.
Drill and exercise performance
Emergency response organization participation
Alert and notification system reliability
The inspectors reviewed a 100 percent sample of drill and exercise scenarios, licensed
operator simulator training sessions, notification forms, and attendance and critique
records associated with training sessions, drills, and exercises conducted during the
verification period. The inspectors reviewed the qualification, training, and drill
participation records for a sample of 12 emergency responders. The inspectors
reviewed alert and notification system maintenance records and procedures, and a
100 percent sample of siren test results. The inspectors also interviewed licensee
personnel that were responsible for collecting and evaluating the performance indicator
data. The inspectors completed three samples during this inspection.
-16-
Enclosure
b.
Findings
No findings of significance were identified.
4OA2 Problem Identification and Resolution
.1
Annual Sample Review
a.
Inspection Scope
The inspectors selected 6 condition records (corrective action program inputs) and
13 problem evaluation requests for detailed review based on their linkage with event
classification, notification of offsite authorities, and processes for providing protective
action recommendations. The records were reviewed to ensure that the full extent of
the issues were identified, an appropriate evaluation was performed, and appropriate
corrective actions were specified and prioritized.
b.
Findings
No findings of significance were identified.
.2
Biennial Maintenance Rule Identification and Resolution of Problems
The inspectors reviewed selected corrective action documents associated with
Maintenance Rule related findings. With one exception, the inspectors verified that
Energy Northwest took, or planned, appropriate corrective measures for identified
issues.
On December 10, 2002, Energy Northwest personnel initiated Problem Evaluation
Request (PER) 202-3461. The PER, categorized as nonsignificant, was dispositioned
and closed on February 4, 2003, based on actions to be taken as identified on the PER
resolution form. There were three specific actions identified, all associated with some
aspect of Maintenance Rule scoping review. Energy Northwest personnel closed the
PER when they initiated an individual plant tracking log (PTL) for each of the three
actions. The PTL was an additional corrective action document used to cause a review,
evaluation, and implementation of specified actions.
The inspectors initiated a review of the three PTLs to verify that a resolution to each of
the conditions had been effected since it was noted that all three PTLs had been closed.
PTL H 194829 was appropriately closed on March 20, 2003. PTLs H 196658 and
H 196664 were shown to be closed on April 15, 2003, and August 28, 2003,
respectively. Closer review by the inspectors, however, revealed that the identified
actions needed to resolve the individual conditions had been transferred to the Mrule
Open Scoping Issue list. This list is a non-proceduralized and uncontrolled document
created as an aide to the Maintenance Rule Coordinator in an attempt to keep track of
Maintenance Rule scoping questions requiring resolution. Therefore, the conditions
originally documented as deficiencies on a PER have still not been corrected, yet all of
the associated corrective action documents have been closed out. This is a minor
violation of Criterion XVI in Appendix B to 10 CFR Part 50.
-17-
Enclosure
Additionally, the Mrule Open Scoping Issue list contained 56 scoping issues, only 2 of
which had been closed. Review of several of the open issues revealed that some had
resolutions which appeared to close the item, but they were still shown as being open.
The majority of the issues appeared to deal with the question of whether certain
structures or components, or their functions, should be included in the scope of the
Maintenance Rule. The inspectors were able to ascertain that the list contained open
scoping issues that dated back to at least July 2002.
Energy Northwest personnel initiated on September 23, 2004, Condition Report (CR)
CR 2-04-05341 to review and evaluate the two conditions discussed above.
.3
Cross-References to Problem Identification and Resolution Findings Documented
Elsewhere
A problem identification and resolution crosscutting aspect was identified for actions
needed to resolve individual conditions had been transferred to the Mrule Open
Scoping Issue list. This list is a non-proceduralized and uncontrolled document created
as an aide to the Maintenance Rule Coordinator in an attempt to keep track of
Maintenance Rule scoping questions requiring resolution (1R12).
A problem identification and resolution crosscutting aspect was identified for the
effectiveness of Energy Northwest's problem identification and resolution processes
regarding exposure tracking, higher than planned exposure levels, and radiation worker
practices (Section 2OS2).
4OA3 Event Followup (71153)
.1
July 30, 2004, Automatic Reactor Scram and Alert Declaration
a.
Inspection Scope
On July 30, 2004, the inspectors observed and evaluated Energy Northwests response
to an automatic reactor scram and Alert declaration which was made at 10:00 p.m. PDT.
The inspectors responded to the control room and verified the status of plant conditions
by observing key plant parameters, annunciator status, and observing the current status
of safety related mitigating equipment. The inspectors also observed reactor operator
actions in response to the plant scram and senior reactor operators evaluation of plant
conditions and oversight of the reactor operators. Following the declaration of the Alert,
the inspectors relocated to the technical support center to observe Energy Northwests
response to the event to ensure that actions taken were commensurate with established
emergency implementing procedures and that technical support center staffs evaluation
and assessment of plant conditions and emergency response was adequate. Energy
Northwest subsequently terminated the Alert at 11:57 a.m. PDT after verifying that plant
conditions were stable and that the initial criteria for which the Alert had been declared
no longer were met. During a post event review, the inspectors reviewed operator logs,
plant computer data, condition reports, and conducted interviews with plant employees
to evaluate the appropriateness of operator actions and to verify plant response.
-18-
Enclosure
b.
Findings
Operator Response to Automatic Scram and Alert Declaration
Introduction. An Unresolved Item was identified pending the NRCs determination of the
regulatory aspects and evaluation of the safety significance of the performance issues
associated with Energy Northwests Alert declaration.
Description. On July 30, 2004, at 9:23 a.m. PDT, an automatic reactor scram occurred
due to a high pressure condition. The high pressure condition occurred when the No. 1
Main Turbine Governor Valve drifted closed as a result of the associated control circuit
card failure. Following the automatic scram, the reactor operators actuated alternate
rod insertion (ARI) after noting that two control rods did not indicate fully inserted.
Operators had been trained that with more that one control rod not fully inserted
following a reactor scram that a control rod pattern did not exist which alone always
assured a shutdown reactor under all conditions. Approximately two minutes after ARI
was activated all control rods indicated fully inserted.
A prompt determination whether the reactor scram occurred because of a valid reactor
protection system (RPS) actuation was not made. Energy Northwest noted that at
08:13 a.m. PDT a surveillance activity, Procedure, ISP-MS-Q909, ATWS/ARI/RPT Trip
Reactor Pressure, had been approved for performance. Conduct of this procedure had
the potential for causing a reactor scram if not properly performed. The shift manager
initially considered that the RPS trip may have been caused by the conduct of the
surveillance activity and therefore the RPS trip may not have been valid. In fact,
although procedure ISP-MS-Q909 had been approved for performance, it had not
actually been started at the time of the scram. The shift managers review of one of the
reactor pressure chart recorders did not identify any increase in pressure which
preceded the automatic scram. At 9:53 a.m. PDT, the shift manager determined that a
valid RPS trip had occurred because of high reactor coolant system pressure. This
determination was made following the review of plant computer data which indicated a
reactor system pressure increase preceding the automatic scram.
The Emergency Plan Implementing Procedure (EPIP) 13.1.1, Classifying the
Emergency, Revision 32, described in Emergency Action Level 2.2.A.1 the following
criteria for declaring an Alert: 1) any RPS setpoint (including manual) has been
exceeded per Technical Specification 3.3.1.1; 2) RPS actuation failed to result in a
control rod pattern which alone always assures reactor shutdown under all conditions,
and; 3) manual actions (mode switch in shutdown, manual push buttons and ARI) result
in reactor power less than or equal to five percent. After reviewing the EPIP and
considering the initial rod indications and subsequent determination that a valid RPS
actuation had occurred, the shift manager declared an Alert at 10:00 a.m. PDT.
Following the Alert declaration, Energy Northwest notified offsite local and state
authorities, and activated its emergency response organization including activation of
the technical support center, emergency operating facility, and joint information center.
Additionally, Energy Northwest officially notified the NRC Headquarters Operations
-19-
Enclosure
Officer at 10:58 a.m. PDT, of the Alert declaration and activated the Emergency
Response Data System (ERDS) at 11:03 a.m PDT. After determining that the plant
conditions were stable and that the conditions for declaring the Alert no longer existed,
Energy Northwest terminated the Alert at 11:57 a.m. PDT.
A subsequent review of plant computer data by Energy Northwest determined that all
rods had fully inserted during the initial plant scram and that the position indications for
the two indeterminate control rods had not registered the rods where fully inserted until
approximately 2 minutes following the scram. Energy Northwest retracted the Alert
declaration on July 31, 2004.
Energy Northwest determined that the operators had indications available at the time the
scram occurred for determining that conditions for declaring an Alert had not been
satisfied. Specifically, Energy Northwest determined that the operators had multiple
indications available to demonstrate that all control rods had inserted during the scram.
For the 185 total control rods in the core, 183 of the control rods initially indicated fully
inserted (prior to ARI manual initiation). ARI causes a redundant scram by relieving the
scram air header independent of an RPS actuation. Energy Northwest concluded that
the operators should have realized that with 183 control rods indicating full in that the
scram air header was already depressurized and that actuation of ARI did not result in
any additional rod movement. Energy Northwest later determined that the two control
rods had only experienced indication problems. The inspectors reviewed Energy
Northwests assessment and concluded that although information was available to
determine that all rods had inserted, that at the time of the event the control room staff
made the correct and prudent decision to initiate ARI given the training they had
received to check the rod worth minimizer for all rods inserted indication.
The inspectors noted the following performance issues:
1. Immediately following the reactor scram, the reactor operator acknowledged and
reset the alarming annunciators. This reset and cleared the annunciators which would
have provided information to the shift manager in establishing the validity of the RPS
trip. In addition, the operators failed to identify those annunciators which provide entry
conditions into the emergency operating procedures. Operating Instruction OI-9,
Operations Expectations and Standards, Revision Z, Section 13.0, Annunciator
Response, provides that during transient/EOP [emergency operating procedure]
implementation that alarms are promptly evaluated and operationally significant alarms
communicated by the operator to the control room supervisor. Those annunciators
flagged as potential EOP entries are assessed by the operator and communicated to the
control room supervisor as EOP entry conditions including parameter, value, units, and
trends.
2. Prompt measures were not initiated to determine the cause of the reactor scram
including review of the computer alarm logs and each of the reactor pressure chart
recordings. The shift manager indicated that he had reviewed one of the reactor
pressure chart recordings which did not indicate a pressure increase prior to the scram.
However, the post event review clearly indicated a pressure increase on the three chart
-20-
Enclosure
recorders. Additionally, immediately prior to the scram, the control room received
average power range monitor upscale alarms. These alarms provided indication of a
plant anomaly which could include a reactor pressure increase.
3. The shift manager did not contact the personnel responsible for performing
surveillance Procedure ISP-MS-Q909 and therefore was unable to rule out the potential
for conduct of the surveillance procedure being the cause of the reactor scram.
4. The declaration of the Alert was not initiated until 37 minutes after the reactor scram.
At the time of the event, the shift manager concluded that ARI was responsible for final
insertion of the two control rods. The inspectors noted that the information needed for
the shift manager to make the Alert declaration (based on the actions taken) was
available within 15 minutes of the reactor scram.
5. At the time that the Alert declaration was made at 10:00 a.m. PDT, the conditions for
declaring the Alert no longer existed since all rods indicated full in. Emergency Plan
Implementing Procedure EPIP 13.1.1, step 3.7, Transitory Event Classification,
provided that a transitory event classification be made whenever it is discovered that a
condition had existed which met the emergency classification criteria, but where no
emergency had been declared and the basis for which no longer exists.
An Unresolved Item (URI) 50-397/04-04-03, was opened for the NRC review of the
performance issues associated with the operators response to the reactor scram and
the declaration of the Alert. The inspectors noted that Energy Northwest initiated
immediate actions to provide control room staff training and briefings on evaluating plant
conditions to verify full rod insertion and expectations of verifying all available plant
indications when verifying the validity of RPS trips
Analysis. The issues associated with the reactor scram and declaration of the Alert
classification are under review by the NRC staff. A determination of the safety
significance associated with any performance deficiencies will be addressed in the
resolution to the unresolved item.
Enforcement. The issues associated with the reactor scram and declaration of the Alert
classification are under review by the NRC staff. A determination of the enforcement
aspects associated with any performance deficiencies will be addressed in the
resolution to the unresolved item.
Emergency Response Data System (ERDS)
Introduction. An NRC identified Green NCV was identified for Energy Northwests
failure to activate ERDS within one hour. This was identified as a violation of 10 CFR 50.72(a)(4).
Description
Energy Northwest activated ERDS 63 minutes after the Alert declaration. The NRC
questioned the status of ERDS following the Alert declaration and noted that the system
was not activated within one hour after declaring an Alert.
-21-
Enclosure
Analysis.
Energy Northwests failure to activate ERDS within one hour as required by 10 CFR 50.72(a)(4) was determined to be a performance deficiency. The inspectors determined
that the failure to activate ERDS within the prescribed time limit was of more than minor
risk significance because it was associated with an actual event response performance
deficiency that affected the emergency preparedness cornerstone objective to ensure
that Energy Northwest is capable of implementing adequate measures to protect the
health and safety of the public in the event of a radiological emergency. By not
activating ERDS within the required time, Energy Northwest hindered the NRCs ability
to verify plant conditions to ensure the appropriateness of any licensee recommended
emergency response actions. Manual Chapter 0609, Appendix B, Emergency
Preparedness Significance Determination Process (EP SDP), section 2.2(e), states that
a failure to activate ERDS constitutes a failure to comply with the requirements of
10 CFR 50.72(a)(4) and should be considered a failure to implement under the EP SDP.
Utilizing Sheet 2, Actual Event Implementation Problem, of the EP SDP, the inspectors
determined that the finding was of very low safety significance (Green). Although the
finding was associated with an implementation problem during an actual Alert
declaration, the failure to comply with the requirements of 10 CFR 50.72(a)(4) did not
constitute a failure to implement a risk significant planning standard.
Enforcement.
10 CFR 50.72(a)(4) required, in part, that a licensee shall activate ERDS as soon as
possible but not later than one hour after declaring an Alert. Contrary to this
requirement, on July 30, 2004, Energy Northwest declared an Alert at 1000 but did not
activate ERDS until 1103. This violation is being treated as an NCV, consistent with
Section VI.A.1 of the NRC Enforcement Policy (NCV 50-397/04-04-04, Failure to
Activate the Emergency Response Data System Within One Hour). Energy Northwest
documented this issue in their corrective action program in Condition Report 2-04-
04103. Corrective actions included assigning additional on-shift personnel the duty of
activating ERDS to ensure timely activation.
.2
Reactor Scram due to Loss of Reactor Feedwater, August 15, 2004
a.
Inspection Scope
On August 15, 2004, the reactor plant was manually scrammed due to lowering reactor
vessel water level when the Reactor Feedwater Pump A (RFW-P-1A) unexpectedly
tripped. RFW-P-1A was the only feedwater pump in service at the time. The inspectors
observed plant conditions and operator response following the plant trip to ensure that
the reactor plant was stable and that operators were adhering to plant procedures. The
inspectors also verified alarm printouts and the status of mitigating equipment to
determine if there was any unusual plant response to the loss of feedwater and
subsequent plant scram.
-22-
Enclosure
b.
Findings
Introduction. A Green self-revealing finding was identified for Energy Northwests failure
to adequately monitor condenser hotwell level after raising hotwell level above a high
hotwell level alarm setpoint. This contributed to the operators not identifying a hotwell
excursion in a timely manner which resulted in a loss of reactor feedwater and a
subsequent manual reactor scram. No violations of NRC requirements were identified.
Description. On August 9, 2004, in anticipation of a reactor startup following a forced
outage, reactor operators raised the in-service hotwell level controller COND-LIC-1
setpoint from its nominal setpoint of zero inches to a higher control setpoint of +5.5
inches (the upper end of the control band and indicating range for COND-LIC-1 was
+6.0 inches). The operators raised the setpoint to support a plant forced outage water
management plan to accommodate additional water storage in the condenser hotwell
during the reactor startup. As a consequence of operating the hotwell at a level of +5.5
inches, the hotwell high level annunciator which had a setpoint of +3 inches was locked
in. The operators recognized this condition and implemented hourly logs of hotwell level
while the high level annunciator was locked in. The reactor was subsequently brought
critical on August 14, 2004. On August 15, 2004, while at 18 percent reactor power,
operators raised reactor power which resulted in an increase in feedwater flow from the
hotwell to the reactor and a subsequent lowering of hotwell inventory. Controller COND-
LIC-1 responded per design to the lowering hotwell level and directed water from the
condensate storage tanks to the hotwell via the make-up line and then the surge line.
However, as hotwell level increased, controller COND-LIC-1 did not respond to close the
make-up and surge line isolation valves. Level in the hotwell continued to rise above the
indicating range and eventually overflowed to Main Drain Tank No. 1 (MD-TK-1). RFW-
P-1A automatically tripped on a high level condition in MD-TK-1. With RFW-P-1A
tripped, reactor vessel level lowered in response to the loss of feedwater. Operators
manually scrammed the reactor prior to receiving an automatic scram on low reactor
vessel level (level 3).
A post event review conducted by Energy Northwest determined that Controller COND-
LIC-1 operated per design during the event and had not failed. It was determined that
the cause of failure of the hotwell level control system to restore and maintain hotwell
level at the automatic setpoint of +5.5 inches was due to operators selecting an
automatic setpoint which was too close to the upper operating range of the controller.
Once hotwell level increased beyond the top of the indicating and controlling range for
Controller COND-LIC-1, the controller failed to detect any further increase in hotwell
level as the detected level was fixed at +6.0 inches. The controller design was such that
given enough time it would have detected the +0.5 inches difference between the
sensed hotwell level of +6.0 inches and the setpoint of +5.5 inches and closed the
make-up and surge line isolation valves. However, the hotwell overflowed causing the
trip of the reactor feedwater pump and the plant was manually scrammed prior to this
occurring.
The inspectors noted the following performance issues:
1. Hourly logs by the operators to monitor hotwell level while the high level alarm was
locked in was not sufficient to monitor level in the event of a level transient. By
-23-
Enclosure
operating the Controller COND-LIC-1 at +5.5 inches, there was only a +0.5 inch margin
to hotwell level being high out of sight. In the event of a failure of the controller, hotwell
level would have exceeded the top of the indicating range in a matter of minutes.
2. At the time that the operators raised hotwell level to +5.5 inches and placed the
automatic control setpoint of Controller COND-LIC-1 at +5.5 inches, the back-up
Controller COND-LIC-2 was above the indicating range. This was due to differences in
location of the two controllers which resulted in an approximate +0.5 inch difference in
indicated level. The consequence of which was that the back-up controller was not
available for use since its indicated level was already above the indicating range.
3. Operating with the hotwell level above the hotwell level high alarm rendered that
alarm out-of-service as it was locked in and provided no information on level change.
Procedure PPM 1.3.1, Operating Policies, Programs and Practices, Revision 66,
Step 4.18.6.b, required, in part, that each out-of-service alarm should be reviewed by
the control room supervisor to evaluate the need for compensatory measures and
ensure adequate monitoring of the unavailable parameter. Contrary to this procedure,
Energy Northwests compensatory measure of logging condenser hotwell level on an
hourly basis was not adequate to monitor hotwell level with hotwell level maintained at
the top of the hotwell level controller indicating range.
Analysis. The inspectors determined that Energy Northwests failure to adequately
monitor condenser hotwell level in accordance with PPM 1.3.1 while operating with level
high in the indicating range was a performance deficiency and was reasonably within
Energy Northwests ability to foresee and correct and could have been prevented. The
finding was of more than minor safety significance because it was a human
performance issue which impacted the initiating events cornerstone objective to limit the
likelihood of those events that upset plant stability and challenge critical safety functions.
A Phase 2 evaluation was performed in accordance with Manual Chapter 0609,
Significance Determination Process, based on the finding contributing to both the
likelihood of a reactor trip and that mitigation functions would not be available. The
Phase 2 review was performed using the Columbia Generating Station site specific
worksheets. A senior reactor analyst reviewed the Phase 2 results and performed a
limited Phase 3 review. The senior reactor analyst considered the limited time the plant
was at a low power level and adjusted the time in power operations to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. The
condition existed from criticality on August 14, 2004, at 2:56 p.m. PDT until the scram on
August 15, 2004, at 1:03 p.m. PDT. Therefore, the exposure time window used was < 3
days. The initiating event likelihood credit for a transient loss of service water system
was increased from four to three by the senior reactor analyst in accordance with Usage
Rule 1.2 in Manual Chapter 0609, Appendix A, Attachment 2, Site Specific Risk-
Informed Inspection Notebook Usage Rules. This change reflects the fact that the
finding increased the likelihood of the transient with loss of power conversion system,
but the exact magnitude of the increase was not known. The configuration of the
hotwell ensured that the feedwater system function would be lost following any transient.
Therefore, the power conversion system was not given any mitigation system credit in
the worksheets analyzed. Because the system was recoverable by two different means,
the senior reactor analyst gave credit of 1 for the mitigating system function of the power
conversion system. The finding was determined to be of low safety significance.
-24-
Enclosure
Enforcement. While Energy Northwests failure to adequately maintain and monitor
hotwell level contributed to the initiating event, the finding was not subject to
enforcement actions. The condensate system was not safety related and no violations
of regulatory requirements were identified. (FIN 50-397/04-04-05, Inadequate
Monitoring of Hotwell Level Contributes to Loss of Reactor Feedwater). Energy
Northwest documented this finding in their corrective action program in CR 2-04-04547.
Corrective actions included revising an annunciator response and operating procedure
to preclude operation of the condenser hotwell above the high hotwell level setpoint.
.3
Reactor Scram due to Loss of Reactor Feedwater, August 17, 2004
a.
Inspection Scope
On August 17, 2004, the reactor plant was manually scrammed due to lowering reactor
vessel water level when the Reactor Feedwater Pump A (RFW-P-1A) unexpectedly
tripped due to low suction pressure. RFW-P-1A was the only feedwater pump in service
at the time. The inspectors observed plant conditions and operator response following
the plant trip to ensure that the reactor plant was stable and that operators were
adhering to plant procedures. The inspectors also verified alarm printouts and the
status of mitigating equipment to determine if there was any unusual plant response to
the loss of feedwater and subsequent plant scram.
b.
Findings
Introduction. A Green self-revealing finding was identified for Energy Northwests failure
to follow a clearance order instruction which resulted in a low suction trip of a reactor
feedwater pump and a subsequent reactor scram. No violations of NRC requirements
were identified.
Description. On August 17, 2004, an equipment operator failed to follow clearance
order instruction D-COND-RV-177A which was used to isolate and then restore
condensate heat exchangers 1A and 2A from service to facilitate replacement of relief
valve COND-RV-177A. The equipment operator was to jog open COND-V-123A in
order to slowly backfill and vent the heat exchangers following the maintenance activity.
Contrary to the clearance order instruction, the equipment operator fully opened COND-
V-123A which rapidly filled condensate heat exchangers 1A and 2A which resulted in a
low suction trip of RFW-P-1A.
Analysis. The inspectors determined that the equipment operators failure to fill and
vent condensate heat exchangers 1A and 2A in accordance with clearance order
D-COND-RV-177A was a performance deficiency and was reasonably within Energy
Northwests ability to foresee and correct and could have been prevented. The finding
was of more than minor safety significance because it was a human performance issue
which impacted the initiating events cornerstone objective to limit the likelihood of those
events that upset plant stability and challenge critical safety functions. A Phase 2
evaluation was performed in accordance with Manual Chapter 0609, Significance
Determination Process, based on the finding contributing to both the likelihood of a
reactor trip and that mitigation functions would not be available. The Phase 2 review
was performed using the Columbia Generating Station site specific worksheets. A
-25-
Enclosure
senior reactor analyst reviewed the Phase 2 results and performed a limited Phase 3
review. The senior reactor analyst considered the limited time the plant was at a low
power level and adjusted the time in power operations to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. The condition existed
from criticality on August 14, 2004, at 2:56 p.m. PDT until the scram on August 15,
2004, at 1:03 p.m. PDT. Therefore, the exposure time window used was < 3 days. The
initiating event likelihood credit for a transient loss of service water system was
increased from four to threee by the senior reactor analyst in accordance with Usage
Rule 1.2 in Manual Chapter 0609, Appendix A, Attachment 2, Site Specific Risk-
Informed Inspection Notebook Usage Rules. This change reflects the fact that the
finding increased the likelihood of the transient with loss of power conversion system,
but the exact magnitude of the increase was not known. The configuration of the
hotwell ensured that the feedwater system function would be lost following any transient.
Therefore, the power conversion system was not given any mitigation system credit in
the worksheets analyzed. Because the system was recoverable by two different means,
the senior reactor analyst gave credit of 1 for the mitigating system function of the power
conversion system. The finding was determined to be of low safety significance.
Enforcement. While the equipment operators failure to properly fill and vent
condensate heat exchangers 1A and 2A in accordance with clearance order D-COND-
RV-177A was the cause of the initiating event, the finding was not subject to
enforcement actions. Operation of the condensate system was not a safety related
activity and no violations of regulatory requirements were identified (FIN 50-397/04-04-
06, Failure to Follow Clearance Order Instruction Results in Loss of Reactor Feedwater).
Energy Northwest documented this finding in their corrective action program PER 204-
1042. Corrective actions included temporary senior reactor operator oversight of all
pretask briefings and remedial training for the individuals involved.
.4
Reactor Water Cleanup Relief Valve Failure
a.
Inspection Scope
On September 10, 2004, control room operators received alarms and indications in the
control room indicative of a Reactor Water Cleanup (RWCU) leak. Indications included
a RWCU system differential flow alarm, heat exchanger room high temperature
indications, reports from personnel in the reactor building that steam was issuing from
floor drains outside of the RWCU heat exchanger room, and increased radioactive
particulate concentration in the reactor building recirculation ventilation system. The
leak was caused by RWCU heat exchanger relief valve RWCU-RV-3 inadvertently lifting
and failing to close. The inspectors, who were present in the control room when the
event occurred, observed operator response to the abnormal condition to verify that
plant abnormal procedures were followed and to assess the adequacy of operator
actions to isolate the leak. The inspectors also reviewed operator logs, applicable
drawings, and corrective action documents to determine the history of previous similar
relief valve failures. Energy Northwest repaired the relief valve and returned the RWCU
system to service.
b.
Findings
No findings of significance were identified.
-26-
Enclosure
.5
(Closed) LER 05000397/2002005-00: Main Steam Leakage Control Fan potentially
inoperable during a design basis accident due to undersized thermal overloads.
The inspectors reviewed LER 2002005-00 to determine if there were any identified
violations or aspects of human performance associated with the LER. See
Section 4OA7.1 for an associated Energy Northwest identified violation.
.6
(Closed) LER 05000397/2003009-00: Reactor Core Isolation Cooling Rendered
Inoperable due to a 250VDC Battery Cell not meeting TS Requirements.
The inspectors reviewed LER 2003009-00 to determine if there were any identified
violations or aspects of human performance associated with the LER. See
Section 4OA7.2 for an associated Energy Northwest identified violation.
.7
(Closed) LER 05000397/2003010-00: Unanticipated inoperability of the high pressure
core spray system due to isolation valve leakage while the system was isolated.
The inspectors reviewed LER 2003010-00 to determine if there were any identified
violations or aspects of human performance associated with the LER. This event did
not constitute a violation of NRC requirements. Energy Northwest entered this condition
into the corrective action program as Problem Evaluation Request 203-3684.
4OA4 Crosscutting Aspects of Findings
A human performance cross cutting aspect was identified when the control room staff
failed to identify that APRM B was bypassed and out of service during a shift turnover
and did not identify the condition until several hours later even though there were control
board indications which clearly indicated the bypassed condition. Additionally, a senior
reactor operator signed an associated surveillance procedure for closure when he failed
to recognize that an initial block indicating the return to service of APRM B was not
initialed (Section 1R22).
Two examples with human performance cross-cutting aspects were identified which
involved failures to survey (Section 2OS2 ).
A human performance aspect was identified when reactor operators failed to adequately
monitor hotwell level after raising hotwell level above the hotwell high alarm setpoint
(Section 4OA3.2).
A human performance aspect was identified when an equipment operator failed to follow
a clearance order which resulted in a low suction trip of the running reactor feedwater
pump and a subsequent loss of reactor feedwater and manual trip of the reactor
(Section 4OA3.3).
-27-
Enclosure
4OA5 OTHER
.1
Temporary Instruction (TI) 2515/154, Spent Fuel Material Control and Accounting
at Nuclear Power Plants
The inspectors collected the data specified in Phases I and II of the TI. The data was
forwarded to the individuals identified in the TI, for consolidation and assessment.
.2
Retraction of Two Safety System Functional Failure Performance Indicators
On May 26, 2004, Energy Northwest informed the NRC that the reporting basis for two
LERs (LER 50-397/2003-003-00 and LER 50-397/2003-005-00) had been changed from
reportable per 10 CFR 50.73(a)(2)(v) to voluntary. Both LERs involved the interruption
of flow in the residual heat removal system while in the shutdown cooling mode of
operation. Additionally, both events were reported in 3rd quarter 2003 as mitigating
systems performance indicator safety system function failures. 10 CFR 50.72(a)(2)(v)(B) required to report any event or condition that could have prevented the
fulfillment of the safety function of structures or systems that are needed to remove
residual heat. Following the reclassification of the LERs to voluntary, Energy
Northwest retracted both issues from the safety system functional failure performance
indicator in the 3rd quarter, 2004. The NRC is evaluating the acceptability of Energy
Northwest not reporting both loss of shutdown cooling events as failures to fulfill a safety
function per 50.72(a)(V)(B) and the subsequent retraction of both events from the safety
system function failure performance indicator. Pending completion of the NRCs
evaluation, this issue will be characterized as an Unresolved Item (URI 50-397/04-04-
07, Retraction of Two Loss of Shutdown Cooling Events from SSFF Performance
Indicator).
4OA6 Meetings, Including Exit
Resident Inspector Routine Exit Summary
The inspectors presented the emergency preparedness exercise inspection results to
Mr. V. Parrish, Chief Executive Officer, and members of his staff at the conclusion of the
inspection on September 3, 2004. Energy Northwest acknowledged the findings
presented.
On September 30, 2004, the resident inspectors presented the inspection results to
Mr. D. K. Atkinson, Vice President, Technical Services, and other members of his staff
who acknowledged the findings.
On October 2, 2004, the inspectors presented the inspection results to Mr. V. Parrish,
Chief Executive Officer, and other members of his staff who acknowledged the findings.
A subsequent discussion was conducted on October 4, 2004, by telephone with
Mr. D. Coleman, Manager, Performance Assessment and Regulatory Programs and
other members of the staff.
-28-
Enclosure
The inspectors telephonically presented the inspection results to Mr. Doug Coleman,
Manager, Regulatory Programs, and other members of licensee staff on
October 8, 2004.
The inspectors verified no proprietary information was discussed during any of the
inspection exits.
4OA7 Energy Northwest Identified Violations
The following violations of very low risk significance (Green) were identified by Energy
Northwest and are violations of NRC requirements which meet the criteria of Section VI
of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as noncited
violations.
Cornerstone: Mitigating Systems
.1
Energy Northwest identified a violation of Technical Specifications 3.6.1.8, Main Steam
Isolation Valve Leakage Control System (MSLC), which required that one MSLC
subsystem may be inoperable for 30 days. If the MSLC train is not returned to service
within that time, then to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Energy Northwest reported the
problem to the NRC via Licensee Event Report 50-397/2002-005, Revision 0.
Undersized thermal overload relays had been installed in the Train A main steam
isolation valve leakage control fan motor. As a result of not installing the properly sized
thermal overload relays for the fan, the motor was considered inoperable from May 1991
until December 29, 2002, when the properly sized relays were installed. Corrective
actions included verifying the sizing of relays on other fan motors related to the system
and revised appropriate program procedures and electrical drawings to preclude
recurrence. This finding was of very low risk significance because although it did impact
the barrier cornerstone objective, it did not represent a degradation of the radiological
barrier function provided for the control room, auxiliary building, SFP, or SGT system,
the finding did not represent a degradation of the barrier function of the control room
against smoke or a toxic atmosphere, and the finding did not represent an actual open
pathway in the physical integrity of reactor containment or an actual reduction of the
atmospheric pressure control function of the reactor containment. Energy Northwest
captured this issue in their corrective action program as Problem Evaluation Request
202-3581.
.2
Technical Specification 5.4.1.a required, in part, that written procedures shall be
established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation).
Regulatory Guide 1.33, Appendix A, Section 8.b, required, in part, that specific
procedures for surveillance tests be written for emergency power tests. During a review
of LER 2003-009, which documented an inoperable condition of battery E-B2-1 which
affected battery operability, the inspectors noted that Energy Northwest identified a
violation of Technical Specification 5.4.1.a for inadequate acceptance criteria for battery
cell specific gravity in procedure ESP-B21-Q101. Procedure ESP-B21-Q101, Quarterly
Battery Testing 250 VDC E-B2-1, Revision 5, step 8.14.1, stated that the acceptance
-29-
Enclosure
criteria for the difference in specific gravity for an individual battery cell and the average
of all the connected cells specific gravity be less than or equal to 0.20. However,
Technical Specification 3.8.6, Battery Cell Parameters, required that specific gravity
for an individual cell be not more than 0.020 below the average of all connected cells.
Procedure ESP-B21-Q101 was performed on August 20, 2003. On August 20, 2003,
cell No. 166 specific gravity was measured as greater than 0.020 above the average cell
specific gravity. However, because of the inaccurate acceptance criteria, the out of
specification was not identified until August 22, 2003, during a subsequent review of the
test data. Although the finding affected the mitigating systems cornerstone, it was of
very low safety significance (Green) because the finding: (1) did not result in the loss of
function of a safety system; (2) did not represent an actual loss of a safety function of a
single train for greater than its technical specification allowed outage time; and (3) did
not represent an actual loss of safety function of one or more non-technical specification
trains of equipment designated as risk significant per 10 CFR 50.65 for greater than
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Energy Northwest documented this issue in their corrective action program in
PER 203-3125. Corrective actions included revising Procedure ESP-B21-Q101 to
include the correct acceptance criteria and a review of other battery surveillance
procedures to correct any other identified discrepencies.
ATTACHMENT: SUPPLEMENTAL INFORMATION
A-1
Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Energy Northwest
D. Atkinson, Vice President, Technical Services
I. Borland, Manager, Radiation Protection
D. Coleman, Manager, Performance Assessment and Regulatory Programs
D. Dinger, Radiation Protection Manager (Acting)
D. Feldman, System Engineering Manager
B. Gardes, Performance Manager
S. Grundhauser, Maintenance Training Supervisor
M. Humphries, Manager, Engineering
T. Lynch, Manager, Operations
C. Moore, Supervisor, Emergency Preparedness
S. Oxenford, Plant General Manager
V. Parrish, Chief Executive Officer
R. Webring, Vice President Nuclear Generation
NRC Personnel
L. Carson II, Senior Health Physicist
R. Cohen, Resident Inspector
Z. Dunham, Senior Resident Inspector
W. Jones, Chief, Project Branch E
M. Shannon, Chief, Plant Support Branch
ITEMS OPENED AND CLOSED
Items Opened, Closed, and Discussed During this Inspection
Opened
50-397/04-04-03
NRC Review of Performance Issues Associated with the July 30,
2004, Reactor Scram and the Declaration of Alert
(Section 4OA3.1)
50-397/04-04-07
Retraction of Two Loss of Shutdown Cooling Events from SSFF
Performance Indicator (Section 4OA5.2)
Opened and Closed
50-397/04-04-01
Failure to Identify and Return to Service APRM B in a Timely
Manner (Section 1R22)
50-397/04-04-02
Two Examples of Failure to Survey (Section 2OS2)
50-397/04-04-04
Failure to Activate the Emergency Response Data System Within
One Hour (Section 4OA3.1)
A-2
Enclosure
50-397/04-04-05
Inadequate Monitoring of Hotwell Level Contributes to Loss of
Reactor Feedwater (Section 4OA3.2)
50-397/04-04-06
Failure to Follow Clearance Order Instruction Results in Loss of
Reactor Feedwater (Section 4OA3.3)
Closed
50-397/2002005-00
LER
Main Steam Leakage Control Fan potentially inoperable during a
design basis accident due to undersized thermal overloads.
(Section 4OA3.5)
50-397/2003009-00
LER
Reactor Core Isolation Cooling Rendered Inoperable due to a
250VDC Battery Cell not meeting TS Requirements. (Section
4OA3.6)
50-397/2003010-00
LER
Unanticipated inoperability of the high pressure core spray system
due to isolation valve leakage while the system was isolated.
(Section 4OA3.7)
Discussed
None
PARTIAL LIST OF DOCUMENTS REVIEWED
Procedures
PPM 8.4.63; Thermal Performance Monitoring of DCW-HX-1C; June 23, 2004
PPM 1.5.14; Risk Assessment and Management for Maintenance/Surveillance Activities;
Revision 13
ISP-RHR-X304; ECCS-LPCI (B&C) Pump Discharge Low (Min Flow) - CC; Revision 0
PPM 10.24.234; I&C Removal/Reinstallation of IRM/SRM Detectors
ISP-IRM-X306; Intermediate Range Monitor Channel F Calibration; Revision 8
ISP-IRM-W402; Intermediate Range Monitors - Channels B, D, F & H - CFT; Revision 8
OSP-RCIC/IST-Q701; RCIC Operability Test; Revision 28
ISP-LPCS/RHR-Q901; RHR A & LPCS Discharge Pressure - ADS Trip System A Permissive
(By K10A Relay) - CFT/CC; Revision 7
TSP-APRM-C301; APRM and Core Thermal Power Channel Calibration Check; Revision 4
OSP-LPCS/IST-Q702; LPCS System Operability Test; Revision 12
ESP-MSIV-B301; MSIV Closure Limit Switches - CC; Revision 0
-3-
A-3
Enclosure
General Operating Procedure 3.1.1, "Plant Startup," Revision 32
Site-Wide Procedure SWP-OPS-05, Restart Evaluation Process, Revision 1
Operating Instruction OI-004-000, Operation Shift Logs, Revision 28
Administrative Procedure 1.5.14, Risk Assessment and Management for
Maintenance/Surveillance Activities, Revision 13
Administrative Procedure 1.3.5, Reactor Trip Report, Revision 17
OSP-RHR/IST-Q704, RHR Loop C Operability Test, Revision 14
Calculations
Calculation 216-92-057; Weaklink Analysis for Valve No. MS-V-146 and RFW-V-65A,B (Velan
24" 900# Gate Valves); Revision 1
Drawing M551; Flow Diagram HVAC Circ. & M/U Water, S.W. & Diesel Generator Bldg.;
Revision 55
Drawings
ME-02-02-43; Room Temperature Calculation for DG Building, Reactor Building, Radwaste
Building and Service Water Pumphouse Under Design Basis Accident Conditions; Revision 7
Drawing M-519, "Flow Diagram Reactor Core Isolation Cooling System" Revision 86
Other
Technical Specification 3.5, ECCS and RCIC, Revision No. 38
Final Safety Analysis Report Chapter 5.4, Component and Subsystem Design
WO 0108554; RFW-V-65A Electrically Backseat Per System Engineers Direction; August 27,
2004
WO 01082365; RHR-FIS-10B Replacement; June 30, 2004
WO 01062381; Replace IRM-DET-2F; August 18, 2004
WO 01060822; MS-V-22D Disassemble and Reassemble
WO 01077279; MS-V-28D Disassemble and Reassemble
WO 01079061; RCIC-P-1 Change Bearing Housing Oil
FO-04-01 Shutdown Safety Plan
PMR-02-86-0305, Rod Position Information System
-4-
A-4
Enclosure
General Electric Services Information Letter Number 532, Full in Control Rod Position
Indication, dated March 27,1991
PERs / Condition Reports
PER 204-0628; E-IN-3A was running, for testing, in parallel with E-IN-3B which could cause an
overload condition o the Div 1 125 VDC system; March 10, 2004
PER 204-0935; During the performance of PPM 2.10.4 in response to high temps in the DG
rooms, several discrepancies were found on the position of dampers; July 19, 2004
CR 2-04-01508; In 1995 an incorrect stem diameter was applied during diagnostic testing of
MSLC-V-1D. Actual thrust/torque is greater than recorded; April 15, 2004
PER 204-1056; During Panel Walkdown to Perform TSP-APRM-C301 Discovered the APRM-
CH-B Bypass Switch in Bypass; August 25, 2004
PER 202-3056
PER 204-0972
PER 203-3111
PER 202-3581
PER 203-3125
Condition Reports
CR-2-04-03321
CR-2-04-00739
CR-2-04-00783
CR-2-04-02214
CR-2-04-03884
CR-2-04-05341
Problem Evaluation Requests
202-3461
203-2370
203-3782
203-0316
203-4200
203-4174
203-4176
203-0950
-5-
A-5
Enclosure
203-3872
Plant Tracking Log
A 207409
A 206232
A 206370
H 194829
A 207162
A 206234
A 206371
H 196658
A 207166
A 206237
A 206372
H 196663
A 216273
A 206369
A 205042
H 196664
Procedures
PPM 1.5.11, Maintenance Rule Program, Revision 6
SWP-CAP-03, Operating Experience Program, Revision 12
PPM 10.25.105, Motor Control Center and Switch Gear Maintenance, Revision 21
TI 4.22, Maintenance Rule Program, Revision 8
Miscellaneous
SA-2003-0044, Maintenance Rule 2003 Self-Assessment, November 25, 2003
Maintenance Rule (a)(1) Systems, as of September 20, 2004
Maintenance Rule Biannual Period Report July-December 2002
Maintenance Rule Biannual Period Report January-June 2003
Maintenance Rule Biannual Period Report July-December 2003
Maintenance Rule Biannual Period Report January-June 2004
Maintenance Rule Open Scoping Issue List
1EP1 Exercise Evaluation (71114.01)
Columbia Generating Station Emergency Plan, Revision 38
Emergency Plan Implementing Procedures (EPIPs):
13.1.1, Classifying the Emergency, Revision 33
13.2.2, Determining Protective Action Recommendations, Revision 15
13.4.1, Emergency Notifications, Revision 30
13.10.2, TSC Manager Duties, Revision 25
13.10.4, Radiological Protection Manager Duties, Revision 28
13.10.9, OSC Manager and Staff Duties, Revision 35
13.11.1, EOF Manger Duties, Revision 33
13.11.7, Radiological Emergency Manager Duties, Revision 28
13.11.10, Security Manager Duties, Revision 25
13.12.19, Joint Information Center Management, Revision 10
August 4, 2004 Drill Report
ERO Team D 2004 Exercise Summary, August 31, 2004, Management Critique
4OA1 Performance Indicators Verification (71151)
-6-
A-6
Enclosure
Emergency Plan Implementing Procedures (EPIPs):
13.14.8, Drill and Exercise Program, Revision 16
13.14.9, Emergency Program Maintenance, Revision 24
Emergency Preparedness Group Instructions (EPIs):
EPI-11, ERO Administration Program, Revision 6
EPI-18, EP NRC Performance Indicators, Revision 8
EPI-21, Drill and Exercise Performance, Revision 6
Section 2OS2: ALARA Planning and Controls (71121.02)
Procedures
GEN-RPP-01
ALARA Program Description, Revision 4
GEN-RPP-02
ALARA Planning and Radiation Work Permits, Revision 8
GEN-RPP-13
ALARA Committee, Revision 3
SWP-RPP-01
Radiation Protection Program, Revision 5
Corrective Action Documents
CR# 2-04-00205, CR# 2-04-01183, CR# 2-04-01941, CR# 2-04-01942, CR# 2-04-02413,
CR# 2-04-02995, CR# 2-04-03190, CR# 2-04-03283, CR# 2-04-03928, PER-203-2908,
PER 203-2913
Audits and Self-Assessments
Qualitys Integrated Performance Assessment Report (July 1, 2003 through October 31, 2003)
SA-2003-0015 Annual Assessment of the Radiation Protection Program (2003)
Continuous Monitoring Reports - December 2003 through January 2004, February 2004,
April 2004
ALARA Work Packages
30001231, 30001216, 30001227
4OA2 Problem Identification and Resolution
Condition Records:
CR 2-04-02187, Timely and accurate notification to the NRC via ENS may be challenged...
CR 2-04-04103, ... ERDS was activated three minutes beyond the one hour requirement ...
CR 2-04-04292, The ALERT declared during the scram event of July 30, 2004 was determined
CR 2-04-04111, An Alert was declared at 1000 on 30 Jul 04."
CR 2-04-04896, SAE declaration untimely
-7-
A-7
Enclosure
CR 2-04-04920, Control Room failed to timely recognize entry conditions for SAE.
Problem Evaluation Requests:
203-3712, 3786, 3921, 3922, 3926, 3971, 3983, 4424
204-0175, 0429, 0645, 0977, 0993