IR 05000259/1989012
| ML18033A901 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 08/16/1989 |
| From: | Jenison K, Little W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18033A900 | List: |
| References | |
| 50-259-89-12, 50-260-89-12, 50-296-89-12, NUDOCS 8908250168 | |
| Download: ML18033A901 (73) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-259/89-12, 50-260/89-12, and 50-296/89-12 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Square Chattanooga, TN 37402-2801 Docket Nos.:
50-259, 50-260, and 50-296 Facility Name:
Browns Ferry Units 1, 2, and
License Nos.:
DPR 33, 52, and
Inspection Conducted:
April 10, 1989 through April 14, 1989, and May 8, 1989 through May 12, 1989 Inspector:
K.
Jeni so, earn Leader A
iI iran
e Signe Inspectors:
P. I. Castleman, Plant Systems Engineer T. A. Cooper, Reactor Inspector P.
G. Humphrey, Resident Inspector W.
S. Marini, Consultant T.
F. McElhinny, Resident Inspector G. A. Schnebli, Resident Inspector C.
F. Smith, Reactor Inspector Approved by:
.
PL can.
W.
ttle, Sect>on Chief P ojects Section
TVA Projects Division; ADSP Oa Si ned Summary Scope:
This announced inspection involved inspection effort in the area of quality verification.
Licensee quality activities in the areas of operations performance, system lineups, maintenance, surveillance testing, review of previous inspection findings, follow-up of events, review of licensee identified items, and review of licensee corrective actions were evaluated.
Objective:
The objectives of this inspection were to:
Assess the effectiveness of the licensee's line organizations for achieving and self-verifying quality in their functions.
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Note:
For this assessment, quality verification effectiveness is defined as the ability of the licensee to verify quality and to identify, correct, and prevent problems.
It is the aggregate of all efforts to verify quality results and take corrective action when a quality result was not obtained.
Assess the effectiveness of the line management in ensuring that safety-significant problems and deficiencies are dealt with promptly and completely, in response to input from the quality verification organizations.
Assess the communication effectiveness of generic issues within the quality verification organizations and management.
Assess
. the communication effectiveness" of lessons learned and problems from other TVA sites.
Assess the effectiveness of engineering support to correct deficiencies.
Assess the licensee's performance effectiveness relating to the many commitments made to the NRC as a prerequisite for allowing the return to operation.
Results:
No violations, deviations, unresolved items or inspector follow-up items were identified.
One non-cited violation was identified, NCV 259,260,296/89-12-01, Compensatory Measures, in paragraph 2.
Corrective actions for this NCV are considered a
prerequisite for Unit 2 Restart.
Several weaknesses identified during this inspection are identified in the Conclusions subparagraphs of the report.
These areas will be inspected further in the guality Assurance Programmatic Team Inspection to be conducted in the future.
The final assessments described in the above objective can not be made until that team inspection is complete REPORT DETAILS 1.
Persons Contacted Licensee Employees
- J. Bynum, Vice President, Nuclear Power Production
"0. 2eringue, Site Director G. Campbell, Plant Manager
"P. Carier, Site Licensing Manager
"L. Clardy, QA Technical Support Supervisor
"S. Maehr, Work Control Supervisor
"J. Hutton, Operations Superintendent
~S.
Rudge, Site Programs Manager
- J.. Savage, Compliance Supervisor
- A. Sorrel, Maintenance Superintendent G. Turner, Site Quality Assurance Manager R. Tuttle, Site Security Manager
"J. Wallace, Licensing Engineer NRC Employees
- W. Little, Section Chief
- D. Carpenter, Startup Manager
"A. Johnson, Project Engineer
"C. Patterson, Restart Coordinator
"Attended exit, interview Acronyms and initialisms used in this report are listed in the last paragraph.
2.
Quality and Operational Safety Verification
'a
~
Control Room Activities and Plant Tours The inspectors observed control room operations and reviewed applicable logs including the shift logs, night order book, clearance hold orders book, configuration log and TACF log.
No issues were identified with these specific logs.
The inspectors also conducted discussions with control room operators, verified that proper control room staffing was,maintained, observed shift turnovers, and confirmed operability of instrumentation.
The inspectors verified the operability of selected emergency systems, and verified compliance with TS LCO (1)
Reactor Scr am (a)
Description of Activity Unit 2, received a one-half scram signal on April ll, 1989 at 2:00 p.m.
This event resulted from indicated high radiation in main steam line D.
The operator notified the SOS and implemented the appropriate Alarm Response Procedure.
In addition, an AUO and personnel from radiological control were dispatched to investigate the area to determine the validity of the indications At 2:04 p.m.,
the radiation monitor was no longer "spiking."
and the one-half scram signal was reset per instruction from the SOS.
At 2: 14 p.m.,
a spike on both the D
and C radiation monitors in thei r respective steam lines, caused a full scram signal.
The A and B monitors did not indicate that high radiation existed.
The AUO and Radiological Controls personnel reported that no probable cause for the events was found.
As a precautionary measure, all welding and grinding was stopped in the Unit 2 reactor building to eliminate those activities as a
possible source of instrument noise.
(b)
References (c)
Reactor Operator Log Unit 2, LER 89-009, rev. 0.
Conclusions The inspector determined that operations personnel involved in the event were adequately trained and possessed the essential expertise which resulted in proper handling of the event.
In addition, log entries were made to properly describe and document the ongoing activity.
Management was notified within a reasonable period of time per discussions with the Operations Manager.
The operator told the 'inspector that a similar event had recently occurred.
It was suspected to have been caused by craftsmen working in the main steam tunnel.
The craftsmen accidentally bumped the radiation detector which caused the event.
The inspector reviewed the operator logs and found that a one-half scram signal had occurred on February 23, 1989, and again on February 24, 1989.
Further review of the investigation report indicated the cause of the first event was originally thought to have resulted from the craftsmen bumping the monitor, but after the second event,
a thorough checkout of the wiring revealed that the power cable leads in the instrument drawer were loose.
Unit 2 LER 89-009, revision 0 appeared to adequately describe the event, but failed to conclude the root cause for the spurious spikes on the C
and D main steam line radiation monitors.
However, it was stated in the LER that the investigation and communication with the vendor were continuing in order to determine the root cause for the instrument spikes.
To prevent recurrence, welding and grinding activities were di scontinued in the area of the monitors until the signal cables were disconnected and the related trip signals defeated.
The radiation monitors are not requi red by TS in the shutdown mode.
The existing radiation monitors are to be upgraded with new digital monitors that are to provide improved signal conditioning and discrimination.
The inspector determined that the event was responded to and managed in a
satisfactory manner and that the corrective action to replace the monitors appears to be positive'2)
Compensatory Measures (a)
Description of Activity The inspector reviewed the scram incident addressed above, to determine if there were Compensatory Measures to be implemented.
Based on conversations with the licensee, it became apparent that a defined CM program was not fully implemented at the beginning of this inspection.
A request was made by the inspector for a safety evaluation of the individual and cumulative affects of all CM on plant activities and staffing involved in both routine and accident situations.
(b)
References Site Director Standard Practice, SDSP-12. 11, Revision 0, Special Requirements and Compensatory Measures (c)
SDSP-27. 1, Form SDSP-148, Safety Evaluation Review and Approval Form, Subject:
Cumulative Effects of Compensatory Measures on Shift Manning Conclusions At the beginning of this inspection, licensee management stated that a
CM prestartup evaluation did not exist.
The inspector expressed concern that the licensee's effort had
4'
been minimal considering the lead time given to respond to this issue which was an ISEG action issue.
During the second week of the inspection, the inspectors learned that a procedure, Site Director Standard Practice, SDSP-12. 11, rev. 0, Special Requirements and Compensatory Measures, was issued on April 19, 1989, that established a
program to control and track the implementation of CM.
In addition, the safety evaluation requested during the first week of inspection had been performed.
This Safety Evaluation Review and Approval was dated May 8, 1989.
The evaluation addressed the cumulative effects of the compensatory measures on plant staffing requirements as listed in Technical Specification 6.2.2.
A total of 21 CM were identified by the program.
The inspector reviewed a
random sample and no deficiencies were noted.
Discussions with the Operations Supervisor were conducted to determine the method utilized to ensure that the CM were implemented during applicable plant operations.
During this discussion, the licensee stated that the operating personnel received training on CM and a manual with the CM was made available for reference.
Documentation for this training could not be provided.
During discussions with shift operators conducted on May 10, 1989, the inspectors noted that operators did not understand CM or the program.
In addition, applicable procedures have not been revised to reflect CM.
Browns Ferry Technical Specifications require that procedures be established implemented and maintained for certain safety related activities.
Contrary to this requirement several CM have not been included into applicable procedures.
This issue will be identified as a
non-cited violation, NCV 259, 260, 296/89-12-01, Compensatory Measures, and is required to be resolved prior to the restart of any unit.
The characterization of the CM i ssues as an NCV is appropriate because; the licensee is in a corporate improvement program and is presently establishing a
CM program including procedure updates; it meets the current NRC enforcement policy; and the licensee has committed to complete corrective actions prior to the restart cf any unit.
(3)
Fire Match Activities (a)
Description of Activity The inspector reviewed activities which involved the use of fire watche (b)
References PMI 12. 12, Conduct of Operations, Revision 4.
FPP 2,
Fire Protection Attachments, Revision 2.
Attachment F, Fire Protection Equipment and Barrier Penetration Removal From Service.
Technical Specification 3. 11/4. 11, Fire Protection Systems.
LER 50-259/88-026, September 29, 1988, Violation of Fire Protection Technical Specifications Due to Personnel Error,.
LER 50-296/89-001, March 10, 1989, Failure to Provide Required Continuous Fire Watch on Inoperable Fire Doors Caused by Personnel Error Due to Insufficient Training.
LER 50-259/89-005, April 11, 1989, Plant Technical Specifications Surveillance Requirement Exceeded Due to a Misinterpretation by Supervision Responsible for Patrolling Firewatches.
LRED 89-0-018, Inoperable Fire Doors.
LRED 89-0-022, Inoperable Fire Doors.
LRED 89-0-048, LER 50-259/89-005.
(c)
Conclusions PMI 12. 12, section 4.1. 1 states that the operators (all classifications)
are the owners of the plant.
As such, they are required to be knowledgeable and in control of the plant at all times.
When a firewatch is determined to be required, the foreman who makes the determination is responsible for initiating the required forms for the watch.
The fire protection group makes a determination of the compensatory measures required to fulfill Technical Specification requirements.
The Shift Operating Supervisor is tasked with reviewing and approving the compensatory measures.
Several instances have occurred where the compensatory measures did not meet the Technical Specification requirements.
The.corrective actions taken for the instances where the Technical Specification actions were not met, were to train the Fire Protection personnel on the Technical Specification requirements.
In each of these
events, the Shift Operating Supervisor had also reviewed and approved the incorrect compensatory measures, but did not receive additional training.
This lack of recognition of the SOS role in the events is considered a weakness in root cause determination.
In addition, the failure of the SOS to recognize the inadequate compensatory measures is considered a weakness in the SOS training and performance.
b.
Handling of Items With a Potential Operational Impact (1)
Engineered Safety Systems Actuations (a)
Description of Ac*tivity The inspector reviewed multiple ESF actuations since January 1988.
(b)
References LERs concerning unplanned ESF actuations:
50-259/88-001,88-002,88-003,88-005,88-006,88-009,88-011, 88-013,88-017, 88"018,88-019, 88-020, 88"021,88-022, 88-024,88-027, 88-030, 88"031,88-035, 88-042,88-043, 88-044,88-045, 88-047,88-048, 88-049,88-052, 89-007 50-260/88-001,88-002, 88-004, 88"005,88-006, 88-007,88-008, 88-009, 88"011,88-013, 88-014,88-016, 88-017, 88"018,89-005, 89-008,89-010 50"296/88-002,88-005, 88-008,89-003 LREDs related to unplanned ESF actuations:
89-3-042, 89-2-049 Preliminary Investigation Reports for Unplanned ESF Actuations and Root Cause Assessments (RCA)
RCA " 88-01, 88-02, 88-05, 88"13, 88-15, 88-16, 88"20, 88-21, 88-26, 88-27, 88-33, 88-35, 88-38, 88-40, 89"05, 89-26 PMI 15.9, Plant Incident Report, Revision
Reactor Protection System Circuit Protector Performance Report, March 16, 1989 Memo to Guy G. Campbell, Browns Ferry Nuclear Plant-Plant Assessment Section Trend Report for February 1989, March 15, 1989
i "s g
MR 902937, 480V RMOV Bd "2B" Failed to Transfer from Alt. bkr. to Nor. bkr., September 9,
1988 MR 877850, When Breaker is Returned from GE Service Shop Install In Compt 2D of 480V RMOV Bd.
2B, September 24, 1988 MR 903854, Normal Feeder Breaker, Compt 2D 480V RMOV Bd.
2B, Would Not Close During An Attempt to Transfer Board to Normal Feeder, October 2, 1988 (c)
Conclusions During the period from January 1988 to present, there were approximately
LERs generated on unplanned actuations of ESF systems.
Several of these LERs reported multiple events.
These events have been attributed to several different causes, but many of them are related.'even of the ESF actuations during this period involved RPS deenergization events that have involved circuit protectors.
Following an event on March 7, 1989, a task force was formed to look at these and previous events of this type.
This task force reviewed these events and identified a set of recommendations to prevent recurrence.
. However, the recurrence control did not address personnel error, even though it did appear to be a contributor in many of the events.
On September 9,
1988, an ESF actuation occurred when the 2B RPS Bus deenergized during the transfer of the 480V RMOV board 2B to its alternate feed bus.
A Maintenance Request was written to investigate and repair thi s condition.
Maintenance performed inconclusive trouble shooting until the SOS stopped the activity.
The SOS stopped the activity because the breaker was scheduled to be replaced with a
refurbished one.
At no time, had maintenance positively identified the breaker as the cause of the problem.
Subsequently, the breaker was proven not to be the cause of the ESF actuation.
The original MR was closed, the maintenance tags were removed from the breakers and a
new MR was issued to install the refurbished breakers.
No tags were hung on the breakers to show that a
deficient condition existed.
To support plant testing activities on October 2,
1988, two attempts, were made to switch the breakers to their normal'eeder bus.
This caused two unplanned ESF actuations.
These ESF.actuations could have been prevented if the original problem had been corrected or if some means of identifying the discrepant condition with the breakers had been utilize Recurring causes of other ESF actuations include personnel error and inadequate procedures.
The personnel error problems have been dealt with by counseling and retraining.
The inadequate procedures are often revised procedures being utilized for the first time, with the validation being performed during the performance.
These procedures are revised and the event discussed with the operations personnel.
These events are being treated as individual occurrences, with no programmatic approach being utilized.
A program to track and trend recurring problems was developed and implemented in March 1989.
Prior to this, no formal means existed to identify adverse trends in plant operations.
This is an example of poor corporate experience review in that very similar problems existed at Watts Bar and Sequoyah in 1987 and 1988 and were addressed on a
generic basis at those two plants.
A review of a
sample of the ESF actuations also indicated poor root cause determination and weak management involvement in the resolution of safety related issues.
The newly established Browns Ferry program has not existed long enough to gauge its effectiveness.
As part of this new program, a monthly status report will be sent to plant management.
This should ensure involvement by management for the identification and correction of adverse trends.
(2)
Procedures and Drawings (a)
Description of Activity The inspector reviewed procedures and related primary and critical drawings available for operator use, as-a result of events identified in CAQRs BFP 880389 and 881123.
(b)
References CAQR BFP 880389, Revision 1,
May 13, 1988, Inconsistencies Exist Between As-constructed Drawings And The Upgraded Operating Instructions.
CAQR BFP 881123, Revision 0, December 22, 1988, An ECN Was Closed Without The Primary And Critical Drawings Being Revised, Resulting In Differences Between The As-constructed Plant And The Drawings In the Control Room.
Memo to G.
G.
Campbell, May 1, 1989, Browns Ferry Nuclear Plant -
Drawing Discrepancy (DD)
Progress Repor SDSP 9. 1, Processing Drawing Discrepancies, Revision 7.
BFEP PI 87-70, Processing Drawing Discrepancies, Revision l.
SDSP 2. 14, Surveillance Instruction Evaluation, Revision 7.
SDSP 7.4, Procedure Review, Approved Draft.
(c)
Conclusions CAQR PFT 880389, dated May 18, 1988, discusses the inconsistencies that exist between the plant Operating Instructions and the approved system drawings.
The plant determined that no remedial corrective action was necessary to resolve this issue.
Prior to this time, system walkdowns had been performed to identify drawing discrepancies and the resolution of these discrepancies was still pending.
A drawing discrepancy program had been instituted to allow the identification of drawing discrepancies by plant personnel on an ongoing basis.
These two programs were felt to be adequate to resolve the problems between drawings and the procedures.
As of May 1, 1989, there were 1583 open restart drawing discrepancies.
This number has been decreasing, at a rate of approximately
per week, since January 1989.
This number is substantially lower than the target close-out rate of 73 per week, which has been set to ensure close-out prior to unit restart.
The Supervisor of Engineering Drawing Services, who is tasked with the completion of this project, stated that management support has increased since the beginning of 1989, but that further support is needed to ensure successful completion of the task.
The backlog of drawing discrepancies does not include corrections that are required due to the incorporation of ECNs.
CAQR BFP 881123 identifies a discrepancy resulting from the failure to revise the primary and critical drawings prior to the closure of the ECN.
The condition, described in the CAQR, included the following observations:
...The problem of NE issuing a
Design Closure Statement with deficient primary and critical drawings has happened MANY times before.
All of the other known deficiencies were identified by Plant Staff in their review of the closure statement.
Upon identification of the deficiency, a
verbal
e
notification was made to DNE and the associated drawing was revised and reissued prior to ECN/DCN closure by plant staff.
This problem is occurring much to (SIC) often,....
Plant Operating Instructions have been revised as part of an upgrade program.
As part of this upgrade, the procedures were walked down against the as-constructed plant conditions.
These procedures are often field validated during the first performance of the upgraded procedure.
Prior to this validation the procedure upgrade process relies on drawings that may have several outstanding drawing deviations and outstanding modification related conditions.
Several events, such as ESF actuations, have occurred
'during the validation performance.
The general area of drawing deviations, and modification related changes to drawings and procedures, appears to be an area of considerable weakness both from a
management involvement and control basis and a technical adequacy basis.
The licensee discovered at both Sequoyah and Watts Bar that it cannot simultaneously make programmatic and technical changes in its governing technical procedures, and drawings, and continue to modify the plant.
This appears to be a corporate experience review weakness.
C.
QA Survei llances and Audits in Support of Operations (1)
Control Roo'm Audits By QA.
(a)
Description of Activity The inspector reviewed Quality Assurance (QA) Verificati on audits performed in the areas of operations pertaining to operator shift turnover, operator log keeping, operator awareness of CSSC status, and system status.
(b)
References Memorandum (O.J.Zet ingue/J.T.Barnes, dated April 26, 1989),.Nuclear Quality Audit and Evaluation (NQARE)
Audit Report No.
BFA89906.
QMI 602.6 rev.5, Browns Ferry Site Quality Surveillance Monitoring Reports.
Report ¹ QBF-S-89-100 Dates 1-10 thru 1-12-89
e QBF-S-89-156 QBF-S-89-207 QBF-S-89-335 QBF-S-89-449 QBF-S-89-464 QBF-S-89-466 QBF-S-89-473 QBF-S-89-479 QBF-S-89-492 QBF-S-89-521 Report ¹ (cont'd)
1-11 thru 1-19 thru 1-20 thru 2-15 thru 2-,17 thru 2-21 thru 2-22 thru 2-23 thru 2-24 thru 3-01 thru Dates 1-18-89 1-20-89 1-24-89 2-15-89 2-21-89 2-22-89 2"22"89 2-24-89 2-27-89 3-7-89 QBF-S-89-585 QBF-S-89-701 QBF-S-89"896 Shift Operator Logs (c)
Conclusions 3-08 thru 3-08-89 3-23 thru 3-23-89 4-18 thru 4-18-89 The audit results identified a
plant deficiency with respect to clearance tag placement without authorization signatures and/or dates.
In addition, PMI 17. 1, Conduct on Testing, was found to be weak in that a
need existed to ensure proper correlation between testing activities and the activities of the Work Control Group.
Both deficiencies wer e documented and corrective actions identified.
In addition, various quality surveillance reports, written from January 1989 through April 1989, were reviewed.
It was noted that QA plant operations survei llances are being performed on a frequent basis which have been responsible for identifying deficiencies and implementing corrective actions.
The inspector reviewed a
sample of resumes of personnel performing the QA audits and determined each to be qualified for the functions that they performed.
The reviews have generally found plant operations to be satisfactory in the areas of log keeping, configuration control, shift turnovers, and control room conduct.
In conclusion, for the area of operations monitoring it was determined that QA was performing well, and communicating well with line management.
Corrective actions appear to be implemented in response to QA findings and QA participation in this area is improving the quality of plant activities.
However, there is a weakness in the management of corpo'rate experience in the area of conduct of testing.
Issues similar to those identified by QA were identified at Watts
Bar and Sequoyah as many as two years previous to the Browns Ferry findings.
(2)
Falsification of QA records (a)
Description of Activity The inspector reviewed two cases of falsification of QA records, one during the restart test program and one during routine plant activities.
(b)
References AQR 880850, Falsification/unauthorized Changes To An In Process QA Record, October 15, 1988.
CAQR 890091, Falsification Or Unauthorized Changes To In Process Or Completed QA Records, January 30, 1989.
LRED 89-0-013, Attempted Falsification Of QA Records, January 25, 1989.
Memo To All RADCON Personnel, Guidelines For Completion Of RADCON QA Records, March 22, 1989.
RIMS Document 833 881 110 831.
(c)
Conclusions In the first occurrence, a licensee review of test data from the restart test program, discovered discrepancies on test exceptions completed during the testing.
Reviews determined that data, which was required in an original change notice, had been determined to not be necessary and an N/A placed in the data block.
A task force was created to evaluate and determine required corrective actions.
The task force reviewed all work performed by the person and determined which work he had performed by himself and which tasks had been performed in conjunction with someone else.
Physical evidence of the performance, such as strip charts, event recorders, etc.
was reviewed.
The task force was unable to determine if two tests had actually been performed.
These tests were repeated.
The corporate QA department was represented on the task force.
Corporate QA performed a critique of task force performance.
Management was well informed on both the results of the investigation and the effectiveness of the task forc The second occurrence of falsification of gA records occurred when a Radiological Controls Shift Coordinator had forgotten to perform a routine radiological survey and was attempting to alter documentation to reflect that the survey had been performed.
An AUO raised objections, notified the SOS, and the survey was'hen conducted within the allowable grace period.
As a result of the event, the gA records generated by the individual were.reviewed for the previous three months and disciplinary action was taken.
The person was demoted and received time off without pay.
He has since resumed work as a Radiological Controls technician.
His work activities have been directly observed by his superiors and are acceptable to them.
Ouring both of the event investigations, management displayed strong involvement.
Corrective action for the first event included reperformance of those tests where a
doubt existed as to the accuracy of the data.
Corrective action for the second event satisfied the requirements for the performance of the survey and determined that for a
given period that no other surveys were falsified.
These two issues demonstrated good communications and coordination between line groups toward the resolution of technical issues.
Several overall conclusions in the area of operations were arrived at.
Management of line support functions are weak.
Examples of these support functions are root cause analysis, use or corporate experience (ie NER) to improve plant activities, conduct of testing, control of drawing deviations for critical drawings, and compensatory measures.
Although some weaknesses in Operations line management were noted at the SOS level (fire watches, hold orders),
Operations line management appears-to be adequate and very responsive in reactive situations.
With the exception of the issue discussed in paragraph 5 of this report the Operations and gA organizations appear to have good communications and resolve problems well together.
Finally, several new programs have been so recently established that program implementation and effectiveness can not be determined during this inspection.
3, Surveillance Review a
~
Design-Engineering Support of SI Program Implementation (1)
Description of Activity CARR BFP 890071 was written on January 28, 1989 to document a
surveillance test deficiency which involved 'failure of the SBGT system inlet dampers, O-FC0-65-3, O-FC0-65-25, and O-FC0-65-51,
to open within
seconds as specified in the FSAR.
Additionally, Safety Evaluation SEBFCAQ89009 was performed to evaluate the licensee's planned activities prior to startup with the SBGT system inlet dampers not in compliance with the response time specified in the FSAR.
(2)
References:
Procedure O-SI-4.7C, Secondary Containment Integrity Test T
S Section 3.7..B/4.7.B, Standby Gas Treatment system FSAR Section 5.3.4.2, Standby Gas Treatment System Instrumentation and Controls, Revision
Quality Information Request/Release (QIR)
EBEBFN88033, Revision
Task Scoping Document No. BFP-8-1003, Revision
Procurement Request No. BFP-8-1003, Revision
Drawing No 67-M-0-47E610-65-1, Mechanical Control Diagram Standby Gas Treatment System Drawing No.
67-E-0-45E772-1, Wiring Diagram 480V Standby Gas Treatment Train C Schmematic Drawing No.
67-M-47W225-R4, Harsh Environmental Data, EL 565-0, Revision
(3)
Conclusions The inspector reviewed the referenced documents and conducted interviews with licensee engineering staff to determine the technical adequacy of the corrective action taken for disposition of the identified deficiency.
Review of the Safety Evaluation revealed that an analysis of a failure of the SBGT system to perform its safety function, of filtering the releases to the environment during fuel handling, was performed.
The effect of the fai lure on offsite dose, with the fuel in its present condition (decayed in excess of three years)
was also assessed.
Based on a
review of the Safety Evaluation, the inspector determined that the opening time of 55 seco-5s for the SBGT system inlet dampers did not present a safety issue.
An investigation of the technical basis for the stroke time of
seconds was performed.
The inspector determined that a
stroke time for the inlet dampers is not specified in the TS nor the Design Criteria.
The TS surveillance test requirements for the SBGT system are based on (1) pressure drops across the
combined HEPA filters and charcoal absorber banks; (2) output rating and testing of the inlet heaters; and (3) air distribution across the HEPA filters.
The root cause of the deficiency appeared to have been inaccurate data contained in the FSAR concerning the SBGT system inlet damper stroke time.
Licensee management stated that the FSAR would be revised to specify an approximate operating time of one minute, as shown on vendor data sheets for the inlet dampers.
Pursuant to discussions with licensee engineering personnel, the inspector determined.that the inlet dampers are required to be environmentally qualified in accordance with the requirements of
CFR 50.49.
Further discussions with design engineering and system engineering personnel revealed that numerous motors, instrumentation and control components associated with the SBGT system also require environmental qualification.
A review of referenced design output documents was performed to assess the scope of the plant modifications required to accomplish this objective.
The impact of the proposed design changes on the existing surveillance instructions was also discussed with licensee staff.
In light of the numerous equipment changeouts proposed for the SBGT system, licensee corrective actions for the inlet damper stroke times appear to be inappropriate.
Additionally, until the proposed plant modifications have been completed, the impact of the design changes on plant procedures, including surveillance instructions, is indeterminate.
b.
Setpoint and Scaling Documents (1)
Description of Activity CAQR BFQ 890012 was written on January 18, 1989, to document and initiate corrective action for deviations between DNE issued drawings (Instrumentation Tabulation)
and the site implemented scaling and setpoint documents (SSOs).
A total of twelve instruments were listed as having setpoint discrepancies.
(2)
Re'ferences Monitoring Report QBF-S-88-1888, Maintenance-Instrumentation and Control Special Survey BFEP PI 89-17, Nuclear Engineering Setpoint and Scaling Document Preparation and Control, Revision
EEB-TI-28, Branch Instruction, Setpoint Calculations, Revision
TVA memorandum from J.H.
Rhine, Lead Electrical Engineer to D.P. Burrell, Lead Engineering Assurance Engineer, Subject:
(BFEP)
Project Instruction 89-17, Nuclear Engineering
Setpoint and Scaling Document-Preparation and Control, dated April 4, 1989 2-SIMI-74B, RHR System Scaling and Set Point Document 2-SIMI-82B, Standby Diesel Generator Scaling and Set Point Document 2-SIMI-74, Residual Heat Removal System 2-SI-4.2B-20FT,
.RHR Pump Discharge Pressure Functional Test 2-SI-4.2B-20(B),
RHR Pump Discharge.
(3)
Conclusions The inspector reviewed the reference documents and conducted interviews with licensee engineering staff to assess the adequacy of the administrative process and the developed corrective action implemented for the deficiency.
The inspector verified, for selected instruments, that the setpoint calculations shown on the set point scaling documents were consistent with the calibration procedures.
This result agreed with the licensee's conclusion that the deviations did not present an operability concerns The inspector determined that the root cause of the deficiency was a
lack of design engineering controls for transmitting Setpoint Scaling Document (SSD)
information from DNE to the plant staff.
Pursuant to discussions with licensee management concerning this issue the inspector was informed that a
new program was developed by ONE to address this concern.
The scope of the program should ensure that all activities associated with the development and issuance of SSD will be controlled via the design-engineering program.
Administrative controls are specified in references 2,
3, and 4.
Licensee management is still reviewing the newly developed program controls to see how the program may best be implemented in the field.
A trial use was started in April 1989 and involved SSD for the Standby Liquid Control system.
The inspector determined that a
DCN had not yet been issued for transfer of the SSD to the plant staff.
The inspector concluded that the immediate corrective action implemented for CAQR BFQ 890019 was technically adequate.
Additional corrective actions developed to address an apparent design engineering programmatic weakness also appear adequate.
However, the new program, which incorporates the above corrective actions, has not been in effect a sufficient-amount of time to determine if it will be effectiv,
Drawing Deviations (1)
Description of Activity LER 296/88-07 was written on December 30, 1988, to report an event involving overheating of Diesel Generator 3C because of loss of emergency equipment cooling water.
(2)
References PMI 15.9, Plant Incident Report, Revision
SDSP 9. 1, Processing Drawing Discrepancies BFEP PI 86-53, Control of Design Baseline and Verification Program Action Items BFEP PI 88-05, Control of NE Action Items CAQR BFP 880172, Drawings do not agree with FSARs which are the basis for the plant license, dated February 24, 1988 (3)
Conclusions The inspector reviewed the referenced documents and conducted interviews with selected licensee engineering staff to assess the adequacy of the administrative controls and the developed corrective action plan for the reported deficiency.
The LER assigns the root cause of this event to untimely implementation of drawing corrections.
The inspector determined, however, that the root cause of the problem was programmatic.
The administrative controls for disposition of Drawing Discrepancies (DD) are specified in reference 2.
Review of this procedure and discussions with engineering personnel revealed that an initial review for adverse effect on plant operation or nuclear safety is required for potential 00.
This process failed in that operability concerns were never identified during the initial screening process and therefore a
CAQR was never written to escalate the issue to senior management attention.
In this particular case, this, resulted in a failure to force the DD to closure.
Corrective actions developed and implemented to address this programmatic weakness involved revising procedure SDSP 9. 1.
Paragraphs 6. 1. 1, and 6. 1.7, of SOSP 9. 1 specify the requirements for performing operability evaluations.
Additionally, reference 1 was recently developed and implemented by the licensee to define a formal process for the investigation a'nd reporting of unusual plant occurrences or events which are referred to by the licensee as incidents.
The scope of
reference
involves incident analysis and evaluation to identify the true root cause and contributing factors to events or equipment failure.
References 3, 4, and 5 were reviewed and discussed with licensee engineering personnel to assess the degree of involvement of the DNE organization in the disposition of DD.
The inspector concluded that the initial root cause analysis for the event reported by LER 296/88-07 was inadequate.
This demonstrated an apparent lack of management involvement in assuring quality and...resolving safety issues from a
nuclear safety standpoint.
There appears to be a
generic problem regarding the evaluation of deficiencies that should be dispositioned via CAQRs.
The recently developed and implemented corrective action programmatic controls should improve this situation as it relates to the disposition of DD.
However, this recently implemented program has not been in place for a
sufficient period of time to determine if it wi 11 be effective.
d.
Scheduling, Planning and Work Control (1)
Description of Activity
'Personnel errors committed during surveillance performance were reviewed.
The inspectors reviewed the licensee's process for the performance and coordination of plant activities involving safety related survei llances.
In addition the inspector reviewed the licensee's control of complex surveillance activities (test director concept).
(2)
References:
LRED 89-2-49 LER 2-05000260-88-11 88-15 88-16 88-17 89"03 89-04 89-05 CAQR BFQ890014 BFN Site Quality - Quality Department - Quality Improvement and Readiness Trending Reports for January, February, and March, 1989.
BFN Plant Assessment Section Travel Reports for February and March 198 BFN LRED Summary Report for 1988.
Conclusions The inspectors reviewed the above documentation to assess management actions in response to personnel errors that occurred during surveillance testing.
These personnel errors resulted in several ESF actuations.
The scope of the review expanded into ar eas other than surveillance testing as information became available.
Personnel error related problems, as documented in the trend reports reyiewed, exist in virtually all site organizations, and indicate that there is a serious problem with personnel error at Browns Ferry.
The inspectors determined that the levels and distribution of personnel error were significant because they were all documented through the highest levels of the licensee's problem reporting administrative and corrective action systems on site, ie LER, LRED, and CARR.
The number of personnel related, CAgRs issued during the period January through March, 1989 were 21,
and
per month respectively.
These CAgRs represented a large portion of the CAgRs written in each month.
These statistics were-drawn from reference (d) reports, which are prepared for the Site Director by the Site guality Manager and copies are distributed to all major site management personnel.
Corrective actions for adverse trends are initiated by the equality Improvement organization through the issuance of Trend Analysis Actions, or, for trends which continue to be adverse over three reporting periods, a
significant CAQR is written.
Reference (e) documents the trends of LERs with respect to their root causes.
These reports are submitted to the Plant Manager by the Plant Support Superintendent, with dissemination to plant management staff.
The two reports received (for February and March, 1989) specifically state that the 1989 data shows that if the present trend continues, the number of LERs with this apparent cause will exceed the 1988 total of 23.
For the first quarter of 1989, there were a total of 12 LERs submitted which were attributed to personnel error.
Programs exist at Browns Ferry to identify, track, trend and correct problems which adversely affect the plant.
The necessary information is available to management for initiation of generic corrective action.
The act-i ns taken to remedy personnel error at Browns Ferry. have, to date, been ineffective, and are indicative of a reactive approach to management.
gA involvement in this area.
appears to be mainly statistical in nature and does not appear to have contributed significantly to the resolution of the generic issue.
There was no evidence that actions had been initiated by responsible management to address the generic issue of personnel error, despite the large number
~
~
of widely disseminated indicators.
This issue is a continuing impediment to the restart of Browns Ferry.
e.
Test Deficiencies (1)
Description of Activities During the performance of surveillance instruction O-SI-4.9.A.l.a (8),
a member of the operations staff observed that the 8 Diesel Generator Fuel Oil Transfer pumps did not start until the day tank oil level had decreased to 230 gallons.
Additionally the pump stopped when the level increased to 245 gallons.
The setpoints at which the fuel oil transfer pump was started and stopped were not in accordance with those required by the operating instruction.
Maintenance Request MR 913211 was written to document the deficiency and initiate corrective action.
The developed corrective action plan involved calibrating the level switches in accordance with the requirements of procedure EMI-120.
(2)
References:
O-SI-4.9.A. l.a (8),
Diesel Generator 8 Monthly Operability Test TS Section 3.9/4.9, Auxiliary Electrical System FSAR Section 8.5.3.4, Diesel Fuel Oil Storage and Transfer System MR¹ 913211,
"8", Diesel Generator Fuel Oil Pumps fail to start during O-SI-4.9.A. l.a (8)
PMI 17.1, Conduct of Testing, Revision
NIZAM Part 1, Section 2. 16, Corrective Action, Revision
Drawing No. 0-45E767-3, Wiring Diagram, Diesel Generators Schematic Diagram, Revision
EMI-120, Calibration of Diesel Generator Fuel Oil Day Tank Level Switches (3)
Conclusions E
The inspector reviewed the reference documents and conducted interviews with licensee staff to determine the technical adequacy of the process and the developed corrective action.
PMI 17. 1, paragraph 4. 17, defines a test deficiency as any condition during which the equipment or system being tested either:
(1) fails to operate; (2) operates in a
suspected or
adverse manner; (3) operates outside the limits of documented acceptance criteria; or (4) when inoperable equipment prevents the completion of a test.
Paragraph 4. 17.5 requires that the test deficiency be reviewed to determine if a Condition Adverse to guality exists.
If this determination is made, the test deficiency is required to be dispositioned via the CARR process to ensure that appropriate management attention is focused on the corrective action.
Additional program controls established for disposition of test deficiencies are described in paragraph 2. 1. 1.0 of NIZAM Part 1,
Section 2. 16.
This paragraph requires that test deficiencies, which indicate that an item/component does not comply with the licensee design basis or will affect plant TS, shall be dispositioned via the CARR process if, accept-as-is or repair actions are contemplated.
The inspector determined that this conditional requirement restricts the number of test deficiencies with potential operability concerns that are dispositioned via CAgRs.
Additionally, this conditional requirement is inconsistent with the requirements of PMI 17. 1.
The disposition of the identified test deficiency via MR 913211 did not provide for performing a root cause analysis of the deficiency.
The programmatic controls for dispositioning of surveillance test deficiencies do not describe the degree of management involvement required to resolve possible safety significant issues..
f.
Measuring and Test Equipment (M&TE)
(1)
Description of Activity Based of the issuance of several CA(}Rs/PROs issued against the M&TE program at Browns Ferry, the inspector assessed the evaluation and correction of the deficiencies documented therein.
This assessment was conducted by personnel interviews and review of the following documents.
(2)
References CAgRs 890053, 890096 PRDs 890094P, 890095P, 890142P, 890163P, and 890212P SDSP 29. 1, Control of Measuring and Test Equipment SOSP 3 '3, Corrective Actions
Conclusions The inspector reviewed the licensee's process for the conduct of out of tolerance (OOT)
investigations for lost/damaged/out-of-calibration METE.
Particularly, the reviews focused on the initiation, evaluation, and corrective action regarding four CAQRs/PRDs which identified deficiencies in the performance of OOT investigations.
One CAQR documented the technical inadequacy of an OOT investigation, and the remainder of the reports documented several OOT investigations which were overdue for completion.
The governing procedure for this activity is SDSP 29. 1.
When the CAQRs/PRDs reviewed were issued, Revision
of this procedure was in effect.
This revi sion required OOT investigations to be completed and returned to the M&TE coordinator within 15 days.
CAQR 890053, initiated on January 20, 1989 as a result of a
quality control surveillance, documented six OOT. investigations which were not completed and/or were missing information necessary to provide justification for the acceptability of the out-of-tolerance condition.
The apparent cause of the deficiencies which resulted in the CAQR, as identified by the responsible organization, was inadequate guidance given in SDSP 29. 1 for performing and documenting out of tolerance investigations.
Besides providing additional explanation, clarification, and disposition of the OOT investigations cited in the CAQR, the corrective action specified revision of SDSP 29. 1 to provide specific detailed requirements for performing OOT investigations.
Among the changes to the procedure was a softening of the turn-around time requirement for OOT investigations.
Specifically, the procedure was changed from "...shall be investigated and dispositioned within
working days..." to "...should be investigated and reported to the M&TE coordinator within 15 working days...."
PRDs 890094P and 890095P, and CAQR 890096 documented several OOT investigations which were past their
day deadlines for resolution.
PRO 890095P, which cited three overdue OOT investigations, was revised to incorporate the 26 additional overdue OOT investigations documented on PRDs 890142P.,
890163P, and 890212P.
One of the purposes of conducting OOT investigations is to determine the use made of the subject M&TE, and to evaluate whether this use may impact operability of systems or equipment.
For example, if a
meter used to calibrate a
TS related instrument is found OOT, an assessment must be performed to see
if the operability of the calibrated instrument is questionable.
Such a situation could, in fact, place the plant in an LCO.
Each of the CAQRs/PRDs reviewed had been assessed by the Management Review Committee (MRC) as not potentially impacting operability.
Thus, 890094P and 95P were designated PROs.
890096 was designated as a
CAQR because it documented six overdue OOT investigations.
PRDs 890142P, 163P, and 212P were all included with PRD 890095P documenting a total of 29 overdue OOT investigations.
Despite this large number of investigations overdue, the PRO was. not upgraded to a
CAQR because the cognizant section management stated that they were aware of the problem, and were preparing a "global" corrective action.
It appears that, in these instances, the responsible
.management personnel did not demonstrate adequate sensitivity to potential plant safety problems.
Particularly, the MRC, by evaluating these CAQRs/PRDs as not potentially affecting operability, completely bypassing the established method for assessing NTE operability impacts.
Additionally, the softening of the MME OOT turn-around requirement will allow an already loose system, to lose additional effectiveness.
It is significant to note that Sequoyah allows only 5 days for turn-around of OOT investigations.
This is also an indication of weak Browns Ferry management involvement in the area of corporate nuclear experience review (NER).
~
Nuclear Experience Review (NER)
(I)
Description of Activity The transfer of corporate experience involved with the upgrading of the surveillance programs at Matts Bar and Sequoyah to Browns Ferry was assessed.
(2)
References NER 870519 NER 870536 Memorandum from V.S. O'Block to R,J.
Ogle dates April 7, 1988, documenting information used to perform the BFN Surveillance Procedures Upgrad (3)
Conclusions The above references, as well as personnel interviews, indicated that the experience gained at other TVA nuclear sites in the area of surveillance procedure upgrade was made available to Browns Ferry management for application to their surveillance upgrade program.
However, management decisions were made which reduced the effectiveness of the Browns Ferry program in comparison to the sister program at Sequoyah.
These decisions resulted in a
signi.ficant reduction in the quality of surveillance instructions (SI) produced by the BFN SI upgrade program.
At both Browns Ferry and Sequoyah, an Independent Review Group ( IRG)
was established to provide independent verification and validation of a
sample of upgraded SI.
The Sequoyah IRG consisted of between
and
members who performed technical verifications and walkdowns of a large portion of upgraded SIs.
As well, the Sequoyah IRG observed the validation runs of about 20% of upgraded SIs.
The Browns Ferry IRG consisted of personnel performing technical review and validation observation of a
random sample of upgraded SI.
A TVA Nuclear Performance Plan, Volume III, commitment was made for the IRG to observe and validate 10% of upgraded SI.
The IRG was disbanded after the 10%
commitment was met, even though it had uncovered several significant problems.
Management decisions made in the initial Browns Ferry Program applied a
lower level of effort and independent verification, walkdown, and validation at Browns Ferry than Sequoyah and-resulted in a direct adverse impact on the success of the SI program.
This impact is evidenced by:
the need for an average of roughly 12 immediate temporary changes (ITC) or non-intent changes (NIC) per SI validation and; the recent re-verification and walkdown of all SIs, precipitated by the large number with procedural inadequacies.
h.
Temporary Instruction Changes ( 1)
Description of Activity As a result of a recent NRC inspection the licensee instituted a
revalidation of procedures in the field prior to their us (2)
References The inspector evaluated line management involvement in this new procedure validation effort by reviewing a
sample of approximately 40 non-intent instruction changes that were generated for plant procedures.
(3)
Conclusions In a
random sample of approximately forty non-intent changes there were several that appeared to have an effect on the outcome of the surveillance.
Examples of the type of changes that appeared to affect the outcome of the surveillance included changing setpoints on a transmi.tter, changing a valve position, allowing the use of a particular MME, and changing a
flow requirement to a
volume requirement.
The number and type of changes that are presently being generated by the inplant validation effort are symptomatic of at least the following weaknesses:
Procedure Changes are being incorrectly processed as non-intent changes in order to take advantage of the post performance review process.
The original procedure validation process did not appear to be well executed.
The control room design review and increased operator awareness has added a large number of tagging, and labeling procedure changes.
The elimination of the Independent Review Group appears to have been premature in that only a ten percent sample was taken and lessons learned from Sequoyah SI review efforts were not incorporated.
Browns Ferry continues to modify plant systems generating additional as-constructed drawing, procedure and walkdown difficulties.
4.
Maintenance Review
a
~
Temporary Alterations (TACFs)
(1)
Description of Activity The licensee experienced approximately seven unplanned actuations of engineered safety feature (ESF)
components during the time period from September, 1988 through March, 1989, associated with temporary plant changes.
Although the root
',J
. <<'l)lJ
causes were different for each of these events, a
common element was involved in that each event was related to installing jumpers or lifting leads.
This led the inspector to review the licensee's control of temporary alterations.
(2)
References LER 50"260/88-10 88-11 89-03 89-05, LER 50-259/88-30 PMI-8', Temporary Modifications, Revision
Numerous guality Surveillance audits (3)
Conclusions The licensee has several methods for controlling temporary plant conditions.
These include:
plant instructions, post maintenance test instructions, maintenance requests, and temporary alterations (TACF).
TACFs are controlled by PMI 8. 1.
Licensee management has been directly involved in reducing the number of open TACFs.
Weekly status reports are submitted to senior corporate management.
Open TACFs are also reviewed during the quarterly PORC meetings.
The licensee committed to reduce the number of TACFs affecting Unit 2 restart to ten or less.
In addition, recent changes have been made to the TACF program to ensure existing TACFs are physically verified to be in place and are in good condition.
The first walkdowns performed by system engineers are near completion with numerous discrepancies identified.
Most of these discrepancies were minor and were corrected within a reasonable time frame.
A review of numerous guality Surveillance Monitoring Reports was conducted.
These audits identified minor deficiencies and adequate corrective action.
Overall, the licensee is adequately addressing the outstanding TACFs for Unit 2 restart.
The periodic review of open TACFs by guality Surveillance and Systems Engineering should ensure adequate control of the TACFs.
Manager;.,"..nt appears to be adequately involved in the control of the TACF program.
The plant events associated with TACFs appear to be limited to weak implementation of plant work activities indicating a weakness in management control.of plant work activitie b.
Work Requests (1)
Description of Activity This activity involves two separate component failures.
The first is the failure of the 1C Diesel Generator Lube Oil Circulating Pump in March, 1988.
The second is the failure of the 1A RHRSW pump in November, 1988.
(2)
References Maintenance Request A-867663 MMI-6, Scheduled Maintenance, Standby Diesel Generators MMI-O-OOO-PR0017, General Torquing Guide Maintenance Request A-918209 LRED 88-247 Operators Logs Dated 11-2-88 and 11-4-88 NPRDS General Report Dated 4-10-89 (3)
Conclusions On March 3, 1988, Maintenance Request A867663 was initiated to replace the 1C diesel Generator Lube Oil Circulating Pump.
The cause of this failure was determined to be "normal age and use" by the responsible engineer.
A review of procedure MMI-6 revealed that an annual cleaning of the pump idler, rotor and head is required, and that the pump is to be replaced/rebuilt every three years.
Conversations with cognizant personnel revealed that, although this pump failure occurred prior to the 3-year replacement interval, it is the first such instance of this happening, and therefore, a
more frequent replacement schedule was not warranted.
A review of the completed MR package revealed the following concern regarding gC verification.
Although step 9.4.5 of the replacement sequence required gC verification of bolt torquing, such verification was not performed.
A hand-written note by the cognizant engineer stating
"use craftman's discretion" apparently caused this inspection point to be neglected.
This appears to be an unauthorized
"intent" change to a procedure.
Completed MR are not reviewed by a
second independent technical reviewer in the same manner that an intent change would be reviewed.
This is a
further indication of a
programmatic weakness discussed in section 3. h. of this repor On November 2, 1988, during the performance of SI-4.9.A.1.a (A),
the Al RHRSW pump failed to start on an auto-start signal.
The originally cited cause of the test failure was that the feeder breaker was mi saligned, and therefore, MR A-918209 was initiated to realign the breaker.
The cause of failure stated on the MR form.was that the breaker was out of alignment.
Subsequent to this action, the pump still failed to start.
Further troubleshooting revealed that the fuse block in the A shutdown board was installed in the off position, where upon the operator was notified.
The fuse block was correctly placed in the on position, and the SI.was successfully completed.
An entry was made in the operator's log and on the MR form to document the incorrectly positioned fuse block and LRED 88-247 was initiated.
The above described actions appear to be acceptable.
However, when the completed MR form was reviewed for trending purposes, the condition of the mispositioned fuse block was not entered into the computerized data base, and therefore, does not appear as a
cause of failure in the NPRDS General Report.
Conversations with various supervisory personnel indicate that, in the past, trending data may not have always been entered by technically oriented individuals.
In addition, a review of the NPRDS General Report dated 4-10-89 reveals that approximately 45% of the root causes listed come under the general category of normal wear and use or normal aging.
A concern exists that the widespread use of such reasons for failure may indicate either an inappropriately superficial root cause review or the necessity to regulate preventive maintenance schedules to preclude components failing due to wear and aging.
Inadvertent Backseating of 2-FCV-74-67 Description of Activity The inspectors reviewed MR A869976 which was initiated on March 29, 1988 because the RHR inboard isolation valve 2-FCV-74-67 was inadvertently backseated.
This MR was issued for disassembling the valve and inspecting for damage.
The backseating occurred during the performance of a
functional test following replacement of the power cable and raceway.
The post modification test required motor rotation verifications The work instructions required the operator to hand crank the valve in the mid position, bump hand switch (HS) 74-67 in the closed direction, and then to verify the valve was moving in the closed direction.
If the valve moved in the wrong direction the cable terminations were to be rolled and the valve bumped in the closed position again.
During this verification the operator turned the switch to close the valve but the valve was not bumped (i.e., start the motor and then immediately stop it), but '"
was cycled full open until the thermal overload protection
r stopped the motor.
The valve operator was di sassembled ahd inspected.
The spring pack bearing was replaced and the valve reassembled.
Problems were encountered when post maintenance testing was performed on April 5, 1989.
While attempting to obtain thrust verification MOVATs signatures, the valve failed to open.
Investigation revealed that the thermal overload devices had actuated.
The cognizant engineer determined that the overloads actuated due to repeated opening and closing of the valve (jogging).
The overloads were reset and the operator attempted to open the valve after sufficient cooldown time.
After what the engineer believed was sufficient time for the valve to open had passed and no characteristic sounds observed, the operator was instructed to stop the valve.
A second attempt was made" at opening and after two or three seconds the valve stopped.
The thermal overload devices were found to be actuated.
Additionally, the valve couldn't be manually opened.
The licensee took numerous repair actions which included:
performance of a
meggar test on the motor to determine insulation integrity; loosening of the motor operator mounting bolts in order to work the valve off its seat; performance of a thermal trip test on the thermal overloads.
The insulation integrity was adequate and no degradation had occurred.
The overload heaters were found set at 85 percent and increased to 110 percent in order to achieve the required trip times.
The thermal overloads were also analyzed by the design organization and were found to be correctly sized.
The torque switch and spring pack assembly were also replaced as precautionary measure.
The
.valve was MOVATs tested and successfully completed required survei llances and returned to service.
The licensee's root cause analysis identified that the first unsuccessful opening attempt occurred due to insufficient time allowed to complete opening of the valve.
The second attempt failure was due to the loss of the mechancal hammerblow function, and upon energizing the motor, it immediately stalled.
The licensee concluded that no failure of the valve or operator occurred during the MOVATs testing.
This conclusion was supported by the successful stroking of the valve during post maintenance testing and during surveillance t~~>Sing.
During a
review of the workplan that, was completed for power cable and raceway replacement a deficiency with the test procedure was identified.
The procedure did not address the requirement for testing the particular type of overload relays.
As a result, a
CA(}R was initiated to.retest these relays that were installed and tested prior to issuing the new instructions.
The licensee completed additional corrective actions which included limiting
'
the number of cycles a valve can be subjected to and adding a
caution about removing the hammerblow function.
(2)
References MR A869976 MR A916006 MR A783154 Morkplan 2826 - 88 Failure Investigation Report 89-08 CAQR BFP 890361 Operating Thrust Calculations (OTC) -251 Electrical Corrective Instruction (ECI)
0-000-MOV001, Maintenance For Limitorque Motor Operated Valves ECI - 0-000-MOV003 Limitorque MOV Testing Using MOVATS (3)
Conclusions The inspectors reviewed the licensee evaluation of the March 28, 1989 backseating of valve 2-FCV-74-67 and subsequent problems during troubleshooting and testing.
The modifications group determined the following contributed to the backseating of the valve:
The workplan writer assumed the operator understood the literal and implied meaning of bump.
It was not understood who was in charge of the plant activity and responsible.
The workplan did not have a
caution statement that the valve was unprotected except by thermal overloads should it run in the wrong direction.
These factors were outlined in a April 27, 1989, incident report.
The inspector held. discussions with modifications supervision during the second week of the inspection.
The modifications manager indicated that these issues had been addressed by adding cautions to the computer generated workplans for valves.
A caution was included to describe what a
5ump is and another caution to alert personnel that no protection exists other than
thermal overload devices during this tdsting.
Discussions were held with modification personnel to reemphasize that they are in charge of testing and responsible for the proper performance.
The licensee root cause investigation was adequate.
However, the fai lure investigation report was not initiated until after the valve was returned to service.
The licensee interfaced with the valve and operator vendors effectively to determine if any damage could have been done by backseating the valve.
The maximum thrust at which the weakest valve member ( stem) will yield was higher than, the maximum possible thrust experienced.
Therefore the valve should be safe to operate.
This position was stated in a memorandum from the Acting Manager, Maintenance Planning and Technical Manager to the Operations Manager dated April 7, 1989.
The licensee's corrective actions should preclude recurrence of this type of event.
However, these actions were not identified promptly and the failure investigation was not initiated until after the valve was returned to service.
This event is an example of weak management control of plant activities both from the standpoint of the test director concept and the performance of a failure evaluation to ensure that the component was operable prior to its placement into service.
d.
Configuration Control (2A and 2B Drywell Equipment Drain and Sump Pumps)
Description of Activity (2)
This activity involved configuration control on the 2A and 2B Drywell equipment drain and sump pumps while wiring changes were performed to achieve correct motor rotation.
References MR A786199 MR A864367 CAQR BFP 881095 (3)
Conclusions In December 1988, while performing post-modification testing on the 2A and 2B Orywell Equipment Drain Sump Pumps, it was discovered that the pumps were rotating backwards.
Maintenance Requests A786199 and A864367 were initiated to correct this condition by instructing that the Tl and T3 wires be swapped at the pump motor to achieve the correct rotation.
However, instead of swapping the wires at the pump motor, the wires were
swapped at the 2A Reactor MOV Board.
This action resulted in the wiring at the board being inconsistent with drawing requirements, and CARR BFP-881095 was initiated to document the condition.
The originally proposed corrective action was to generate a
DD in order to revise the drawing to reflect the as-installed configuration.
This proposed disposition was rejected by the Electrical Maintenance Department as being an inappropriate method of maintaining configuration control.
The dispositioning party then issued Revision 1 to the corrective action section of the CARR, again requesting that a
DD be initiated, and attempted to obtain gA approval for such action.
The gA Department also rejected the proposed disposition for similar reasons and requested a
more appropriate corrective action.
After additional correspondence and resolution of gA comments, the proposal to use the DD system to resolve this configuration problem was approved for "this isolated case."
This appeared to be an issue that had adequate technical and administrative resolution.
Management was knowledgeable and communicated across organizational boundaries.
As long as this does not become the norm, the inspector had no further questions.
Hold Orders (2)
De seri pti on of Activity This activity involved the failure to obtain a Hold Order prio~
to performing work on a safety related component.
References Work Plan 2076-86 PRO BFP 880869P SDSP 14.9, Equipment Clearance Procedure, Revision
SDSP 8.4, Modification Workplans, Revision
(3)
Conclusions While performing a
review of completed work plan 2076-86 on Sept.
12, 1988, the modifications engineer discovered that Hold Orders had not been established prior to commencing work, as was required by step 2.0 of the Work Plan.
This Work Plan covered the replacement, of valve 2-FSV-43-14 with an environmentally qualified valve.
Upon discovery, the engineer initiated PRD-BFP880869P.
This failure to obtain the required Hold Order appears to have beeA caused by a
combination of personnel failing to follow procedures, and a
procedure that was
g,,a<
~ p inadequate in tha't it did not contain sufficient administrative controls to ensure compliance.
Although the Work Plan stated that a Hold Order was required and SOS permission was required prior to commencing work, no space was provided for the SOS to indicate his permission had been obtained and no space was provided in which to record the Hold Order number.
Subsequent to this occurrence, a general revision to procedure SDSP 14.9 was instituted, which contains more appropriate administrative controls.
A review of the current revision of this procedure and conversations with supervisory personnel reveal that several procedure enhancements should alleviate a
number of earlier concerns.
These enhancements include:
The requirement that all points of control for a device (i.e.
remote switch, local switch, handwheel, etc.)
be tagged to preclude inadvertent operation The requirement for second-party verification of clearance boundaries, tag placement, and tag removal Performance of configuration walkdowns (i.e. valve line-up)
for components within the clearance boundary More detailed instructions for racking breakers in and out.
In addition, the inspector reviewed procedure SDSP 8.4 and determined that the current revision contains sufficient administrative controls to ensure that the SOS is kept aware of, and has given permission for, the commencement and status of work being performed.
f.
Preventive Maintenance (1)
Description of Activity On August 28, 1988 a refueling zone isolation occurred on all three units.
The isolation was initiated due to a
high differential pressure between the refuel zone and the atmosphere.
The high differential was created when the inboard isolation damper 1-FCO-64-6 closed isolating the ventilation supply fan from the refuel zone.
Subsequent investigation revealed that the damper operator diaphragm had ruptured.
A review of maintenance records revealed that this diaphragm was sched<rl,.d for replacement once per refueling outage.
However, because of the length of the present outage the expected service lifetime was exceeded.
On September 9,
1988 and October 2,
1988 three separate but related events occurred on Unit 2, which involved unplanned initiations of a Reactor Protection System (RPS)
half scram, partial primary containment isolations, secondary containment
'
i solations, and actuation of the control room emergency ventilation system and standby gas treatment.
The root cause was determined to be lack of preventive maintenance on circuit breakers and board compartments.
PMs had not been done during the last two years because of the long outage and the PM frequency tied to refueling outage.
On December 21, 1988, the Unit 3, 3B1 and 3B2 RPS circuit protector tripped deenergizing the 3B RPS bus.
This resulted in the initiation of the ESF logic which included a half scram, primary and secondary containment isolations, Standby Gas Treatment and Control Room Emergency Ventilation.
The circuit protectors tripped due to brief voltage fluctuations in the output of the 3B RPS MG set which were caused by pitting on the contact surfaces of the voltage adjustment potentiometer in the MG set voltage regulation circuit.
Subsequent investigation revealed that PM practices in the past did not specifically address cleaning the voltage adjustment potentiometer and did not incorporate the vendor recommended discontinuity check.
All these events involved PM practices, therefore the inspectors reviewed the current status of the PM program.
(2)
References Preliminary Incident Investigation Report 88-08, dated August 28, 1988 Licensee Event Report (LER) 50-260/88-09, dated October 10, 1988 LER 50-296/88-08, dated January 20, 1989 SDSP 6.2, Preventive Maintenance Program, Revision
SDSP 6.3, Preventive Maintenance Scheduling and Tracking PMI 6.8, Preventive Maintenance Program Assessment PMI 6.22 Preventive Maintenance Upgrade Project NgA 4 E Audit Report No.
BFA89903-Maintenance Improvement Program (MIP)
PM Program Update, dated April 17, 1989 (3)
Conclusions The inspectors reviewed the current (March 1989) trend data and the April 17, 1989 weekly status reports.
.The number of PM
items being performed decreased since all systems for fuel load were signed off.
There is a significant backlog of PM which was discussed with the current maintenance manager.
The current maintenance manager has only been in place since the first of May, 1989.
Interviews with him revealed that he was aware of the large backlog of PMs and the current trends.
The Maintenance Department has an ongoing efficiency study to determine areas where improvements could be made.
The new maintenance manager indicated that appropriate actions will be taken pending the results of this study.
Part of the increase in PM backlog could be attributed to the change in frequency for refueling PM.
As described above, two events were attributed to exceeding the PM frequency due to the extended outage.
To prevent this from recurring, the refueling frequencies have been changed to every
months.
Another factor affecting PM performance was the reduction of personnel.
The Maintenance Manager stated that resource allocation would be determined using the results of the efficiency studies and PM trends.'he Site QA organization performed an audit from February
through March 6, 1989 on the Maintenance Improvement Program.
Their assessment of PM and the PM upgrade program was given to the Site Director.
The PM program was determined to be weak due to the backlog evaluation and implementation of upgrade folders.
However, since this is a
long term goal, it was deemed as acceptable by QA, for Unit 2 restart.
QA determined the PM upgrade program to be strong, well staffed and working.
This program is scheduled for completion by the end of 1990.
The program objectives are to incorporate all internal and external PM requirements for safety related equipment.
QA issued a
CAQR (BFP880515)
previously which identified vendor information not incorporated into PM.
The completion and implementation of the PM folders by the PM upgrade project will be sufficient to close the CAQR.
Discussions held with QA personnel indicated that the generation and implementation of the PM folders was being monitored closely.
The inspectors concluded that the completion of the PM folders and thei r subsequent implementation will help prevent recurrence of the event described in Section 4.f.(1).
The PM Upgrade Program will benefit the site when implementation is achieved.
The Site QA organization was effectively monitoring the site's progress in the PM areas and the audits performed identified important areas for improvement.
The current Maintenance Manager was aware of PM issues, was communicating well with other organizations and appeared to be implementing adequate corrective action.
The backlog of PM remains a weakness as does the possibility that resources may affect the reduction of the PM backlog.
Finally there is not sufficient data to determine if the revised programs will be adequately implemente g.
Trending and Analysi s Corrected on The Spot (COTS)
Program (1)
Description of Activity The licensee implemented the use of COTS for the Quality Assurance/Surveillance Departments in January, 1988.
The COTS provides a mechanism for correction of minor problems identified by QA/QC during survei llances inspections and/or audits.
Because of the recent. large increase in COTS, the inspectors reviewed this area to ascertain the adequacy of the implementation of the COTS program.
(2)
References QMP 102. 14, Corrected on The Spot, Revision 0.
QMP 116.3, Trend Analysis, Revision 0.
December 30, 1988, Memorandum from Site Quality Manager to Site Plant Manager.
May 5, 2989, Q.A. Quarterly Trend Report.
(3)
Conclusions QMP 102. 14 is the controlling procedure for the use of COTS and it defines the identification criteria of COTS attributes.
A COTS is defined as:
'Any encountered deficiencies which can be corrected and recorded as such without issuance of a CAQR or any other required followup action.
For a corrective deficiency to be considered COTS item it must meet all of the following criteria:
A minor deficiency that requires minimum effort for correction.
An occurrence which is reported under NQAM,. Part I, Section 2'6, Corrective Action.
Capable of being corrected within an acceptable time limit by observation of a completed corrective action.
An acceptable time limit is based on the judgement of the individual issuing the COTS.
The time may vary from one hour to the next day.
'I COTS items are described on QA monitoring reports which provide information for trending purposes.
The report includes the number of COTS associated with each attribute, description of
attributes, possible causes, corrective actions taken, and time duration between identification of the deficiency and completion of corrective action.
The QA trend analysis is performed in accordance with QMP 116.3.
The site Quality Manager formats and distributes first and second level reports to the appropriate site organization each month.
The data source is obtained from CAQR, audit results, monitoring results, inspection results, quality engineering document reviews, problem reporting documents (PRDs),
and COTS.
Each quarter a third...level report is issued by QA corporate.
The data used for this report consists of CAQRs, PRDs and COTS.
Any adverse trends are explained as to their causes and effects.
The inspectors reviewed numerous site quality surveillance monitoring reports which generated several COTS items.
In each case the items were within the scope of the COTS program and properly documented.
The corrective actions taken were adequate and performed in a
reasonable time frame. 'he inspectors interviewed responsible licensee QA personnel to determine the organizational understanding and the communication paths which exist to bring adverse trends to the attention of upper management.
The QA personnel were knowledgeable of the structure and process of this function.
A memorandum dated December 30, 1988, from the Site Quality Manager to the Site Plant Manager provided QA's results of monitoring the system preoperabi lity checklist (SPOC)
process.
This review identified numerous findings which indicated additional management attention was necessary.
The inspector also reviewed the May 5, 1989, QA third level trend report.
The inspectors verified that the COTS were being trended according to the procedures and that adverse trends were being identified to upper management.
Overall the use and trending of COTS items is adequate.
There appeared to be good communication across organizational lines and there was adequate management attention given to the resolution of COTS items.
The recent increase in COTS may be the result of recent or proposed organizational changes.
5.
Site Quality Assurance Activities in Support of QVI a
~
Description of Activity Preceding this inspection period, the site QA staff performed audits, inspections, and reviews as part of their normal onsite activities.
In anticipation of this inspection a review of these QA activities was conducted using the QVI format taken from previously conducted NRC inspections.
A sample of these issues was reviewed by the inspector and found not to contain in most cases, a determination of
o
whether or not problems were identified.
For those cases that had problems identified, root cause determinations were not performed, and no determinations on the impact of future plant operations was made.
There were no conclusions drawn from the activities, other than the general one that a particular program existed.
Finally, the site QA organization did not communicate these activities to the line organization and get their concurrence on the activities performed.
References The inspector reviewed the, approximately 20 volumes of the Quality Assurance pre-QVI reviews, and the supporting documentation.
Conclusions As a result of this inspection the licensee undertook a second look at these activities and concluded in several instances that the conclusions met the scope of its corrective action process.
As a
result of the second look, several new issues were identified and several old issues were reaffirmed.
A sample of these issues includes; vender manual control, use of manufacturer data in maintenance, LCO entry control, procedure adherence, and preventive maintenance program adequacy.
In addition, this second look included a concurrence signature by a line manager.
The inspector sampled the conclusions of this QA effort with respect to TVA Restart Criteria committed to in the TVA Nuclear Performance Program.
This was accomplished by taking a sample of CAQRs/PRDs that the second look required resolution on to support Browns Ferry Unit 2 restart activities, and comparing the restart determinations performed by the Restart Readiness Subcommittee (RRS).
A sample of nine CAQRs/PRDs was selected.
The results are as follows:
None of the four PRDs were identified for restart by the RRS Of the five CAQRs three were determined to be nonrestart by the RRS and one written in 1989 was not yet reviewed.
Several weaknesses were identified during this review:
The original QA effort did not have line management participation, root causes, corrective actions, or supported conclusions The second look identified issues that were needed to support the QA determination that Browns Ferry Unit 2 was ready for restart.
Three of these issues were determined by the RRS to be nonrestart.
This weakness identified two inconsistencies.
The RRS is a line function with a
QA representative.
Neither the line nor QA organizations achieved consistency between this QA
effort and the restart determinations made by the RRS.
This appears to be a coordination/communication problem.
The Restart Review Subcommittee is not reviewing such items as MRs, RIR, PRDs, LERs, or DDs.
The reviews conducted to date on these items were/are conducted by different organizations and to criteria that deal mainly with SPOC operability considerations.
The licensee committed in its NPP to review open issues against the restart criteria prior to restart of Unit 2.
These issues were identified in two categories.
The first, Volume 3, CNPP, table IV-1 category was to be reviewed by the RRS using the restart criteria described in section IV of CNPP Volume 3.
The second CNPP, Volume 3,
category (which includes maintenance requests)
was to be reviewed using a restart prerequisite checklist with tracking of open items provided on the SMPL.
The licensee has not yet met this commitment and it may be necessary for the licensee to complete program changes in order to support this review.
Finally, there are several lists of issues which are not included in table IV-1 categories
or 2.
These additional issues include PRDs, LERs, and DOs.
Resolution of these issues is implied in CNPP Volume 3, although the criteria being used by the licensee is a third list referred to as the SPOC.
Implementation and Verification of Commitments made to the NRC a.
Description of Activity The Corporate Commitment Tracking System (CCTS)
was reviewed by the inspector to verify that licensing commitments made to the NRC were being tracked.
.b.
References C.
Site Licensing Section Instruction Letter No.
Conclusions (1)
Verification of Completion of Commitments In addition to the above reference, CCTS records were reviewed with site licensing personnel.
A random sample of commitments to the NRC were investigated to see if they were being tracked on CCTS.
It was found that the tracking of commitments satisfactorily provided the current status of each commitment.
'll commitments inquired of by the inspectors were found to be properly tracked on CCT Late Responses The inspectors desired to assess the ability of the Br owns Ferry Licensing Section to respond to NRC commitments in a timely manner, or to provide the NRC with early notification that commitments will be over due for response.
The inspector determined that the proper mechanism existed to allow for the timely notification to NRC of overdue responses.
Closure Document Errors Site licensing performs technical review of commitment closure packages.
Additional review is provided by the Site guality Surveillance section for all Nuclear Performance Plan, Volume III, commitment closures, and as requested by the licensing section.
Where errors are found, the closure packages are returned to the cognizant section for correction.
The inspector determined that the necessary mechanisms to foster the production of high quality commitment closure packages exist, and that the Site Licensing Staff are aware 'of their responsibilities in this regard.
However, the technical review of nine closure packages recently submitted to the NRC Resident Inspectors office yielded the following results:
Three were satisfactory for closure; one required additional information to complete the technical assessment, and five were technically inadequate.
This appeared to be a weakness in the management control of these licensing activities.
TROI Deficiencies At the time of the inspection, the CCTS commitments were being transferred to the TROI.
As well, the commitments contained in the Operational Readiness (OR) tracking system, which documents the detailed commitments from Volume
of the Nuclear Performance Plan are being integrated into TROI.
The plan for CCTS/OR transfer to TROI included a verification that all commitments have been satisfactorily transferred as well as operator training on the TROI system.
gA or gY Survei llances and Audits As noted in subparagraph (3),
above, the Site equality Surveillance Section reviews some commitment closure packages.
Additionally, the most recent gA audit of the CCTS was reviewed.
In that audit, no problems were noted with CCT sl a
There appears to be adequate QA involvement in the ar'ea of NRC commitment tracking.
The CCTS program appears to be sound and the transfer to the TROI system is being accomplished in a controlled manner.
However, the technical deficiencies with closure packages discussed in subparagraph (3),
above, indicate that additional technical and managerial attention needs to be applied towards the closure of NRC commitments.
7.
Exit Interview (30703)
The inspection scope and findings were summarized on May 12, 1989, with those persons indicated in paragraph 1.
The QVI Team Leader described the areas inspected and each team member discussed in detail the inspection results.
The licensee acknowledged the inspection findings and did not identify as proprietary any of the material reviewed by the inspectors during the inspection.
Inspection Findings; No violations, deviations, or inspector follow-up items were identified.
One non-cited violation (NCV)
259,260/89-12-01, Compensatory Measures, paragraph 2 was identified.
No unresolved items were identified.
8.
List of Acronyms and Initialisms ARI ARP BFEP BFNP BFNPP
~ CAQR CAR CM CREV CS CSSC DCN DG DNE DBVP EA ECN EECW EGM ESF Alternate Rod Injection Annunciator Response Procedure Browns Ferry Engineering Project Browns Ferry Nuclear Power Plant Browns Ferry Nuclear Performance Plan Condition Adverse to Quality Report Corrective Action Report Compensatory Measures Control Room Emergency Ventilation Core Spray Critical Structures, Systems, and Components Design Change Notice Diesel Generator Department of Nuclear Engineering Design Baseline and Verification Program Engineering Assurance Engineering Change Notice Emergency Equipment Cooling Water Electric Governor Motor Engineered Safety Feature
i ~
FPC FSAR GE GET HCU HPCI HPFP HVAC IE IFI ISEG JTG KW LER LRED LOP/LOCA MIC MMI MR MRC NER NOV NPP NRC NRR OI OSP PMI PMT PORC QA QC RP IP RHR RHRSW RPS RTP RWCU SCR SDSP SGTS SI SIL SMPL SNM SPOC SRN SRO TACF TE Fuel Pool Cooling Final Safety Analysis Report General Electric General Employee Training Hydraulic Control Unit High Pressure Coolant Inspection High Pressure Fire Protection Heating, Ventilation,
& Air Conditioning Inspection and Enforcement Inspector Followup Item Independent Safety Engineering Group Joint Test Group" Kilowatt Licensee Event Report Licensee Reportable Event Determination Loss of Power/Loss of Coolant Accident Microbiological Induced Corrosion Mechanical Maintenance Instruction Maintenance Request Management Review Committee Nuclear Experience Review Notice of Violation Nuclear Performance Plan Nuclear Regulatory Commission Nuclear Reactor Regulation Operating Instruction Office of Special Projects Plant Manager Instruction Post Maintenance/Modification Test Plant Operations Review Committee Quality Assurance Quality Control Regulatory Performance Improvement Program Residual Heat Removal Residual Heat Removal Service Water Reactor Protection System Restart Test Program Reactor Water Cleanup Significant Condition Report Site Director Standard Practice Standby Gas Treatment System Surveillance Instruction Service Information Letter Site Master Punch List Special Nuclear Material System Pre-Operation Checklist Specification Revision Notice Senior Reactor Operator Temporary Alteration Change Form Test Exception
TI TS TVA VIO URI USQD Technical Instruction Technical Specifications Tennessee Valley Authority Violation Unresolved Item Unreviewed Safety Question Determination