IR 05000369/1989002
| ML20246J676 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 04/25/1989 |
| From: | Breslau B, Kellogg P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20246J644 | List: |
| References | |
| TASK-3.D.3.4, TASK-TM 50-369-89-02, 50-369-89-2, 50-370-89-02, 50-370-89-2, GL-82-33, IEIN-87-004, IEIN-87-4, IEIN-88-086, IEIN-88-86, NUDOCS 8905170137 | |
| Download: ML20246J676 (49) | |
Text
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< [[eM80ug(..- REGloN 11 ' UNITED STATES . NUCLEAR REGULATORY COMMISSION ' ' 'g 101 MARIETTA STREET, N.W.
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ATLANTA, GEORGI A 30323 k.....,/ Report Nos.: 50-369/89-02 and 50-370/89-02 Licensee: Duke' Power Company 422 South Church Street Charlotte, NC 28242 Docket No.: 50-369 and 50-370 License Nos.
NPF-9 and NPF-17 Facility Name: McGuire 1 and 2 Inspection Conducted:. February 13-17 and February 27-March 22, 1989 Inspectors: /I du4Ie de 2 f /f f'f B. Breslau, Team Leader 1 0 ate Signed , Team Members: J. Arildsen R. Bernhard R. Gibbs B. Desai P. Hopkins C. Rapp R. Schin Approved by:
2C/9D , P. /Ke1Yogg, Chief EfteSigned/ Operational Prog ms Section Operations Branch Division of Reactor Safety SilMMARY Scope: This was a special announced Operational Safety Team Inspection (OSTI).
The OSTI evaluated the licensee's current level of performance in the area of plant operations. The inspection included an evaluation of the effectiveness of various plant groups including Operations, Maintenance, Quality Assurance, Engineering, and Training i in support of safe plant operations.
Plant management's awareness of, involvement in, and support of -safe plant operation were also evaluated.
The inspection was divided into four major areas including Operations, Maintenance Support of Operations, Management Controls, and Emergency Operating Procedures.
The team placed emphasis on interviews of personnel at all levels, observations of plant activities and meetings, extended control room observations, and system walkdowns.
The inspectors also reviewed plant deviation reports, LERs for the current SALP evaluation period, and evaluated the effectiveness of the licensee's root cause identification; short term and programmatic corrective actions; and repetitive failure trending and related corrective actions.
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Results: The licensee's management organization exhibited a high degree of professionalism and control and was well directed to support effective and efficient operation of the plant with both units in Mode 1.
The team observed a number of items which were considered as contributors to proper command and control. Among these were: l Operations shift turnover was well controlled.
Operators displayed l professional attitudes and each appeared to ensure that there was complete understanding of plant status by the oncoming shift.
(paragraphs 2.a and 2.e) Control room access was well controlled. (paragraphs 2.c and 2.f) Shift logs were kept in order and provided current plant status.
Logs were reviewed periodically by plant management and QA personnel.
(paragraph 2.b) Operator response to activated annunciators was immediate and corrective action was taken in a timely manner. (paragraph 2.a) The on-shift Shift Manager processes the tagouts for maintenance to be performed on the next shift.
This allows a prioritization of tagouts, minimizing downtime of the equipment important to safety.
(paragraph 4.a) The licensee's design efforts to improve plant safety are noteworthy.
(paragraph 4.g) The team identified several areas which were considered to be weaknesses.
Of these, inadequate procedures and inattention to procedure adherence was the most serious and resulted in a violation.
(paragraph 4.c.)
The FSAR system description of the control room ventilation doesn't reflect the current method by which the ventilation is controlled.
(paragraph 2.n) There are areas within the plant where housekeeping is of poor quality. (paragraph 2.d) Control of catch-containers appears to be inadequate including deconning of leaking valves and flanges. (paragraph 2.d) There is inadequate contrcl of control room drawings. (paragraph 2.1) There are a number of control room deficiency WRs, and the age and importance of some of these deficiencies are considered a hindrance to safe plant operations. (paragraph 2.m) Labeling of some plant components needs improvement. (paragraph 2.h) ._ . ____ _ __-________-__-_
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The Emergency Operating Procedures have numerous differences from the Owner's Group Guidelines and lack of documentation causes concern as to the adequacy of justifications for deviating from the Owner's Group guidelines (paragraph 3) The lack of dissemination of PRA results to operations training or to planning for use in assigning WR priorities is considered a weakness (paragraph 4.a) Review of the licensee's calculations for determining proper Diesel Generator fuel oil capacity is considered a s an unresolved item.* (paragraph 4.e) , I
- Unresolved items are matters which more information is required to determine whether they are acceptable or may involve violations or deviations.
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-_ - _ _ - _____ _ _-_ __ _- _- _- - __- ,. ' ,. .. .. . REPORT DETAILS i 1.
Persons Contacted Licensee employees
- N. Atherton, Nuclear Production Specialist-
- D. Baxter, Manager, Operations Support
- J. Boyle, Superintendent of Integrated Scheduling
- L. Coggins, General Supervisor, QA/QC
- B. Delonis, McGuire Safety Review Group
- D. Franks, Superivsor, QA Verification
- G. Gilbert, Superintendent, Technical Services
- R. Gill, Manager, Technical Systems
- B. Harkey, Jr. General Supervisor, Mechanical Maintenance
- T. Mathews, Design Engineer
- D. Murdock, Project Manager, Design Engineering
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- B. Reeside, Manager, Shift Operations
- R. Rider, Section Manager, Mechanical Maintenance
- M. Sample, Superintendent, Maintenance
- R. Sharpe,-Compliance Engineer
- G. Swindlehurst, Supervisor, Design Engineering
- B. Travis, Superintendent, Operations
- J. Warren, Lead Engineer, Regulatory Compliance
- J. Weaver, Training
- J. Willis,' Station QA Director Other Licensee employees contacted included instructors, engineers, mechanics, technicians, operators, and office personnel.
NRC Representatives
- K. VanDoorn, Senior Resident Inspector
- R. Croteau, Resident Inspector
- P. Kellogg, Chief, Operational Programs Section, Region II
- E. Merschoff, Deputy Director, Division of Reactor Safety, Region II
- Attended pre-exit interview
- Attended exit interview Acronyms used throughout this report are listed in Attachment 8.
2.
Operations (71707, 71710) Many positive attributes of operational safety can be directly observed in the control room.
These attributes include adequate shift manning, delegation of SS nonsafety related duties, R0 and SRO system knowledge, and relief turnover procedures.
Adequate shift manning assures that qualified plant personnel to man the operational shifts are readily available and that excessive overtime need not be utilized. Delegation of __-__-______ _ _ _ -
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non-safety-related duties assures the SS attention to the command function will.not be diverted to non-safety-related duties. Accurate diagnosis and-response to plant transients, minor and major, requires detailed operator systems knowledge.
Other operational safety attributes can be better assessed through plant tours and system walkdowns. These include material condition; conformance to approved procedures; attentiveness to duties; and return to service of equipment important to safety, including correct system alignment, Finally, interviews with personnel holding a variety of positions on the plant staff, together with some review of records, are necessary to provide-indirect indicators of operational safety and-to corroborate preliminary assessments.
To assess the operational safety of the facility, the NRC team performed extended observations of control room activities, including back shifts, with both units in mode 1.
The team conducted interviews with operators during system walkdowns and plant tours, observed shift turnovers, and reviewed operator logs.
The team also reviewed records used for indication of control of plant status for adequacy and verified operator awareness of their contents.
The NRC monitored operator performance, control room decorum, awareness of plant status, response to alarms, and use of procedures.
The team conducted interviews or plant tours with various managers, superintendents, and first line supervisors within the operations, maintenance, and engineering departments.
The NRC team also reviewed engineering evaluations, training documentation, and maintenance activities as they related to questions that arose from observations in the plant.
a.
Control Room Activities The team observed operational performance during normal and backshift tours.
Shift turnover was observed in the. mornings and evenings.
l Oncoming watch personnel and on-duty personnel were observed conducting very thorough turnovers at their respective stations, and then participating in a pre-shift plant status briefing held by the shift supervisors.
These turnovers were also attended by management personnel on several occasions.
Other personne'l participating in watch station turnovers and plant status briefings, included shift engineers, shift supervisors, control room supervisors, OATC, and auxiliary turbine and service building operators.
Turnovers were completed using briefing sheets, orders of the day, and nuclear control operator turnover check lists.
Discussions centered around existing plant conditions, anticipated plant evolutions, equipment status, operability of certain systems, components, tagging, and personnel assignment @ l ' x.., ' ( :,. l-
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l There were several minor control room alarms that came in during the shift. -The operator at the controls acknowledged each alarm ~1 immediately and initiated prompt corrective action, i Upon receipt of indications of irregular operating conditions in the control room, the -operators quickly verified that appropriate automatic action had taken place. The inspector observed that with 12 hour shifts, the crews appear.to be well adjusted; 12 hour shifts , also appear to be beneficial to operator morale and well being.
j b.- Shift Logs and Records The team observed the shift supervisor, operators, and shift .: engineers enter information into shift control room and station log books.
Entries were neat, legible and if there were any vacant lines, they were lined through to ensure conformity. Where there had been an error, the incorrect information was lined through, and the individual correctly annotated and dated the - entry.
Significant operational events, such as alterations impacting system alignment effecting safety were logged. Entries were on a real time basis and reflected abnormal system and equipment alignments that dealt with plant status.
The team observed operations managers, STAS, supervisors and plant management review the log books.
Logs also contained TS LCOs as appropriate and the roster of personnel on duty for each shift including clarification.
Each licensed unit has its own logbook and the team observed that involved equipment affecting both Units 1 and 2 were documented in both logs.
In each instance where operability was in question, operations personnel had met the operability requirements based upon information recorded in the log.
Plant management and QA personnel were observed reviewing the different logs in the control room.
c.
Control Room Access By observation, control room access was appropriately controlled.
Personnel entering the control room were required to get permission before entering the controlled area.
Directly in front of the control panel for Unit 1 and 2, the area is clearly marked by gray colored carpet.
This area is restricted so that assigned control operators may have continuous unobstructed access to each of the reactor control boards.
It is also used to prevent inadvertent operation of switches by unauthorized personnel who have been given permission to enter the controlled space. On duty licensed operators have the responsibility and authority to control access to the defined area so as to ensure safe operation of both reactors.
Personnel entering the control room to perform certain tasks are told whether the permission is granted for multiple entries to controlled access areas.
There is no smoking, drinking, or eating in the controlled space except by specific authorization for specific licensed personnel. There were no hard hats in the controlled space, only tools and instruments necessary for specific tasks. There are _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -
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specially built' 180 degree swing stiles at' each controlled area entrance. Access to the control room is well defined and adhered to by plant personnel.
d.
Housekeeping and Cleanliness Control During system walkdowns the team noted several areas of the Auxillary-Building where housekeeping and deconning appeared to be weak.
Besides trash and debris in the areas, there were tags broken. and scattered about the floor-. Additionally,.several of the pump rooms had rags piled under components to catch oil or other types of leakage.
There are an unusual number of catch containers around valves. In questioning several people, it was determined that often times catch containers are reinstalled immediately after maintenance completes repairing the deficiency on the valve, component or flange.
Two such instances occurred during the inspection. This pratice is a ' frustration for operators who must work around the catch containers.
There are other instances where Boron has leaked and then crystallized on the component surfaces. Even though there appears to be no other leaks, the area has not been cleaned up, allowing further corrosion of equipment and spread of possible contamination.
The reinstalling of catch containers on good non-leaking valves in " hot" areas appears to contribute to unnecessary personnel radiation . exposure.
e.
Specific' Watch Station and Shitt Turnover The team obsarved shift turn over several mornings and evenings. The on coming shift was observed conducting turnovers at their respective stations and then attending a preshift briefing held by the shift supervisor.
The watch station turnovers observed included shift manager, shift supervisors, control room supervisor, OATC, and the outside of the control room operators. The performance of operating crews during the shift turnover process was very effective and thorough.
The team observed the completion of applicable turnover check lists and discussions of existing plant conditions and anticipated plant evolutions.
During this time the operators maintained adequate staffing in the control room.
Walkdown of the main control boards and instruments was performed by both operators and supervisors.
f.
Conduct of Operations The team observed the conduct of operations.
The licensee conducted plant operations in an effective and consistent manner.
Compliance with procedures covering proper manning levels, shift relief routines, access control, and other activities in the control room was effective.
In response to control board annunciators, operators exhibited a professional attitude.
The NRC observed plant management visibility and the different aspects of effective communications.
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Operators controlled access to the control room area and kept it free of congestion and disturbances.
However, the peak of activities occurred around shift turnover and when maintenance personnel were having work assignments approved in the control room area. These activities were not at anytime excessive and the area of " continuous attention" was always kept free of any congestion and unusual disturbances.
Operators' response to alarms, meter changes and control board annunciators was very good.
The team asked operators detailed questions as to the meaning of annunciators when activated and why some were continuously lit. The NRC also observed operator responses to annunciators on inoperable equipment and other non-expected annunciators.
Most of the annunciators observed were those that activated in response to scheduled and authorized plant surveillance testing.
The observed communications in the control room between supervisors,_ managers, STAS, 0ATCs, auxiliary _ operators and control room operators was casual, yet professional in tone and did not cause any personnel errors.
In a review of approximately 20 LERs, inadequate communications appears to be a contributing factor.
It is reasonable to believe that as communications become more formalized, it'will probably improve professionalism, and provide a means for the reduction in plant personnel errors due to misscommunication.
The NRC frequently observed plant management personnel in the control room areas and throughout the plant assessing plant activities.
On shift operating crews appeared to be adequately rested, alert, and awake and performed their assigned respective duties in a competent-and professional manner.
Additionally, the team noted that the position of STA is a collateral duty of the Shift Manager.
As a result, the STA does not report primarily to the Operations department.
Additionally, the majority of the STA's time appears to be related to the Shift Managers activities.
This affords the STA a very active role in the planning and scheduling of plant surveillance and maintenance activities which requires an in-depth f amiliarity with the daily plant conditions.
While the STA is involved with day-to-day activities, this could prove detrimental to proper prioritization of STA responsibilities, g.
Caution and Danger Tagouts The team observed caution tags to be utilized when there were special instructions or authority was required to operate equipment, prevent or control personnel hazards, or to prevent equipment damage.
The licensee maintained a good resolution between the caution tagout index and the active tags.
There have been two occasions recently where personnel have worked on the wrong component, thereby negating the personnel and plant equipment protection provided by the tagout program.
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I h.
Equipment Labeling The team, while touring both operating units, observed valve labeling to be good.
Labeling of some components, however, is in need of improvement. During walkdowns of the containment spray pump rooms in both units, the team noted that the suction pressure gages for each of' the four pumps were not labeled. There were six label plates on the isolation valve to the discharge pressure gage for the 2B containment spray pump. Additionally, the differential. pressure gage for the air handling unit filter in the 2B containment spray pump room was not labeled.
During this inspection, an incident occurred in which two mechanical -; maintenance technicians took oil samples from the turbine driven auxiliary feed pump on the wrong unit. The WR stated Unit 2 and was red stamped with a 2.. The Unit 2 pump was red tagged out.
The WR required independent verification signatures by both mechanics that they were at the correct equipment.
But they obtained the oil samples from Unit 1 turbine driven auxiliary feed pump, which was in standby at the time.
The licensee will write an LER on this event.
The team inspected labeling at the unit 1 and unit 2 turbine driven auxiliary feed pumps.
The unit 1 pump was clearly identified with green plastic labels. On approaching the pump, five of these labels were clearly visible, each' attached in a different location on the pump or turbine. Each label clearly read : AUX FDW Pump 1, Turbine Driven, IMC APU 0003.
The unit 2 pump was clearly labeled with orange plastic labels. On approaching the pump, three of the labels were visible. Each label read: Aux FDW Pump 2, Turbine Driven, 2MCA , I PU 0003.
The team concluded that labeling of these pumps was adequate and was not a contributing factor to this incident.
L 1.
Key Control The security door system is supplied by vital electrical power, with a battery backup. Should the computerized system fail or lose power, security doors would fail open, assuring operator access to vital areas. In addition, each security door has a security lock override at the door to allow personnel access through the door in an er.ergency egress situation.
When the team walked a system down, the licensee's efforts in establishing and maintaining adequate access to security doors was apparent. Keys are controlled and located in the control room and HP areas. When keys are drawn, radiation equipment is also checked out.
HP personnel checked each piece of equipment to ensure that it would operate before issue.
Present methods of key control allow limited access at all times.
j.
Locked Valves and Lifted Leads The inspection team conducted a walkdown of accessible portions of i the Unit 1 RHR system which included the valve position indication in the control room and the pump, piping, and valves in the RHR pump room.
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The valve positions in the control room were checked against the system flow diagram and licensee valve lineup sheets. The walk down in the pump room did not verify that the valves were positioned correctly, but did verify that all valves required to be locked as noted by the flow diagram, were in fact locked by the licensee. No deficiencies were noted during this walkdown.
Observation of lifted leads and jumpers indicates an overall adequate program for operational status of the plants.
k.
Surveillance Testing The team observed surveillance being performed during the operational performance inspection.
Observation of surveillance throughout this visit were unannounced at varying times on different operating units and equipment with different people. These included control room activities, different tours of the facility and included discussions with numerous plant personnel on different shifts.
Surveillance procedures reviewed are listed in Attachment 1.
Testing was accomplished by qualified personnel.
Proper approvals had been received and verified by testing personnel.
Other observations showed: 1) Surveillance test procedures were technically adequate to perform the testing required to ensure operability.
2) Surveillance test procedures were present in the testing location and followed step by step during performance.
Completion of steps was properly documented.
3) Independent verification was properly performed and conducted, except as noted below.
4) Pretest activities included procedure review prior to sta/t, the required measuring and test equipment was obtained, and shift supervisory / operators authorization was obtained and a discussion of the test and its effects on the plant was conducted.
5) Final review of test results was properly performed and documented, except as noted below.
6) Tests were suspended when required in order to notify the shift supervisor of a test deficiency or correct or clarify procedural deficiencies.
Good communications and close cooperation was observed between the different disciplines and the test performer.
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The team observed performance of PT/2/A/4252/01B, " Vibration Performance Test, 2B Aux Feed Pump", at the feed pump's location.
The controlled. copy of the procedure was in the control room, and a reference copy was used at the pump.. The procedure performs.the ASME Section XI test on the pump to determine component operability.
An irregularity was noted in the method in which data was taken. The procedure required head and differential pressure for flow data at five minute intervals. The individuals performing the test took ten readings over each five minute interval, averaged the values on scratch paper and had the average entered into the' procedure as the' ! five minute value. Two problems result from this method.
As the data that is taken.is not part of. the official record, verification ! of the calculation is not possible.
In addition, an average of differential pressures that is then used to calculate flow will not give the same value as the average of the flows derived from each differential pressure. This is due to the square root being taken of the average of the differential pressures in the method used during the test, versus the square root being performed on each individual differential pressure prior to the averaging the flows in the correct method.
As the data that is taken is not kept as part of the permanent. record, evaluation of past test results is impossible.
The individuals performing the test use an average because they feel the instrument readings are too irregular to use a single value. The , ' makeshift method that is used to compensate for this is not recorded nor is it in accordance with the procedure. This lack of following the procedure results in incorrect numbers entered as the permanent data and results in erroneous results.
Analysis can show that the developed head numbers will result in a good average of the data points, but the flow values resulting from the average of the differential pressure readings will result in a higher flow than the average of the flows.
This result is nonconservative.
1.
Control room drawings
While observing control room operations, a check of the adequacy-and accuracy of control room drawings was conducted by the inspection team. This check was conducted to determine if drawing changes were being incorporated into control room drawings by a method which would assure easy use of the drawings by plant operators. The check also compared control room drawings to the records in site master files to assure that the latest copies of drawings were available to plant operators. This check revealed a number of problems ranging from illegible control room drawings to the latest revision not being available to plant operators.
Problems were not only found in the l control room file, but were also found in the master files.
A listing of the specific problems found by the team is provided in Attachment 2. Due to problems found by the inspection team, as well i as concerns in this area raised about 2 weeks prior to this i inspection by the senior resident inspector, several meetings between ! the team, the senior resident, and several groups of licensee l personnel were conducted, l __-_ _________ _ ___ _ ________J
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During these meetings the licensee provided corrective actions which had already been taken in the area and also made commitments to accomplish corrective actions which had not yet begun.
These corrective actions and commitments are documented in the resident's inspection report 50-369,370/89-01 and will be followed as a part of the close out of Violation 50-369,370/89-01-05 documented in that same report.
! m.
Control Room Deficiencies During control room tours, the inspection team noted that there were many work request stickers on the various pieces of equipment in the shared control room.
As a result, the team asked for and was provided a complete listing of all outstanding control room work requests. Review of this listing dated March 2, 1989 determined that there were a total of 137 WRs outstanding.
Additionally, it was noted that approximately 12 %,(17 WRs), had been issued and were outstanding for over a year.
Discussion with licensee personnel determined that management had recently recognized this situation as a problem area.
As a result, the plant manager, in a memorandum dated February 22, 1989, had established a site goal to reduce the number of control room deficiencies during 1989, to less than or equal to 50 total for both units. As a result of the teams' concern in this area, the team selected a sample of 30 of the WRs for a more detailed review of the problem. The list of WRs reviewed is provided in Attachmens 3.
This review did not note any deficiencies which were in violation of plant TS.
However, problems such as invalid < annunciators, invalid meter indications, and auxiliary oil lift pumps which do not properly function, are a significant hindrance to the operators' ability to safely run the plant and properly control plant conditions.
The large number of control room deficiencies, the age of some of these deficiencies, and the seriousness of some of the specific problems are indications of a weakness in managing the backlog of control room deficiencies.
n.
Control Room Pressurization l
Upon entering the control room, the NRC team observed no rush of air past the door; the control room was not pressurized.
The control
room is common to both units, and both units were at 100% power at the time.
The team then reviewed the TS and FSAR for the Control
Room Ventilation System. The TS require the system to be operable, j and the FSAR states that the control room is continuously pressurized.
j The FSAR design bases for the system include the following statement: ' . " Continuous pressurization of the Control Room and Control Room Area l is provided to prevent entry of dust, dirt, smoke, radioactivity, etc., originating outside the rooms."
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i The team questioned the licensee about the difference between the FSAR description and the actual operating conditions.
The licensee determined that the facility had originally been operated with the control room pressurized. This had been accomplished by running a control room pressurization fan, which brought in outside air through a HEPA filter train. On October 8,1981 the licensee had completed and approved a 50.59 safety evaluation for changing the operating procedure for the Control Room Ventilation System so that the pressurization fan was not normally run.
Since then, the control room has not been continuously pressurized. The safety evaluation stated that the FSAR would be changed at a later date, but this had not been done.
The primary NRC concern in this area has been that the control room is pressurized during accident conditions, and a secondary concern has been intrusion of toxic gasses.
The licensee stated that the control room pressurization fans start automatically on receipt of a safety injection signal. The team.noted that this feature is not described in the FSAR. Then the team verified that periodic testing of this autostart feature is included in the licensee's SI surveillance test procedure, and that satisfactory testing had been accomplished.
In addition, the team reviewed recent control room pressurization surveillance test results, which were satisfactory.
This test demonstrated that the control room could be maintained at a positive pressure of greater than 0.125 inches of water with one of the two control room pressurization fans operating.
The licensee had completed a safety evaluation for this change in operating procedures, as required by 10 CFR 50.59.
However, the licensee failed to revise the FSAR as required by 10 CFR 50.71. The review of Control Room Habitability had been required by the NRC as post Three Mile Island action item III.D.3.4.
The licensee's response to this action item was included in Table 1.8 of the FSAR, and simply stated "See Section 6.4" Section 6.4 of the FSAR describes the Control Room Ventilation System.
The NRC reviews revisions to the FSAR, particularly those revisions that change the facility design or operating procedures in a nonconservative manner.
In this case, the NRC was not provided the opportunity to perform its independent safety review of a change that was made years ago, in 1981.
The licensee stated that the required annual updating of the FSAR has been done by design engineering, which is located offsite at the corporate headquarters.
To find and correct any other inaccuracies in the FSAR, the licensee committed to conduct a review of each FSAR system description, which is to be done by the respective onsite system technical expert. Resultant FSAR revisions should be reviewed
for safety significance and submitted to the NRC as required.
This ' is identified as inspector followup item 369,370/89-02-03.
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L l 3.
Emergency Operating Procedures (42700,25592) 1.
a.
Background Information L Duke Power Company submitted their PGP on 4/13/1983 in response to Generic Letter 82-33, " Supplement I to NUREG-0737 - Requirements for l Emergency. Response' Capability" based on the WOG ERG, Revision -0.
On l 6/8/1984, DPC submitted EP deviations for Catawba based on ERG Revision 1.
On 7/25/1984, DPC submitted additional information requested by NRC for Catawba initial license. An AEOD inspection at Catawba identified weaknesses with the Writers Guide and V&V program.
On.8/30/1988 DPC submitted revisions to the Writers Guide and V&V program.
Currently, no SER for the McGuire EPs has been approved.
b.
Review of the EPs by In-Plant and Control Room Walkdowns The inspectors conducted in plant and control room walkdowns nf the emergency procedures listed in Attachment 5.
Licensed operators were used for control room walkdowns while non-licensed operators were used for in plant walkdowns.
The inspectors verified that indicators, ' , annunicators, and controls were accurately referenced in the EPs, the-steps could be physically performed, and the operators were confident in the procedures-ability to. mitigate the consequences of an accident.
The inspectors identified several human factors concerns listed in Attachment 6.
The number of these concerns brings into question the adequacy of the V&V program.
Currently, the V&V program involves only licensed personnel having an indepth knowledge of what is expected.
The licensee has implemented changes to include non-licensed personnel in the V&V program. The inspectors concluded the procedures could be physically performed as written except as noted in Attachment 6.
(1) Control Room Walkdowns The licensed operators demonstrated sufficient knowledge to execute the EPs; however in several instances the operators relied on theb' interpretation of the intent of the step in order to correctly execute the procedural step. The step could not be fully performed as written without additional guidance.
Licensed operators also used the OAC to obtain parameter values required in the EPs instead of plant instrumentation. Reliance on a non-safety system such as the OAC for parameter verification may cause the operators to provide erroneous information impacting the mitigation action of the EPs.
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l (2) In plant Walkdowns l During the in plant walkdowns, non-licensed operators could not find the correct equipment for performing local operations, did { not fully understand the depth of execution required, and could ! . not access locally operated equipment as directed in the EPs.
) 'Also, the EPs reference equipment location by elevation number ' while non-licensed operators use column number.
This required the non-licensed operator to either ask the control room for the l location or convert elevation number to column number.
The
inability of non-licensed operators to conduct local operations j required by the EPs is safety significant.
During the ! walkdowns, the ir.spectors noted several areas of the turbine i building had trash accumulated behind piping and in hidden corners.
c.
Simulator Exercise Observation ) ) An inspector observed a facility-developed EP validation scenario l involving EP usage by an operating. crew. The facility would not ! allow NRC developed scenarios to be used because the simulator was- ~ not ready for training and the crew had not used the simulator before I this exercise. The inspector concentrated on the usability of the EPs, the operators familiarity with the EPs, the extent of physical interference and duplication of effort, and the efficiency and i thoroughness of procedural transitions.
The observations of the operators ability to use the procedures were used to determine if procedural or training weaknesses existed.
The scenario observed consisted of a LOCA Outside Containment with Loss of Emergency Recirculation. Two procedural deficiencies were i noted.
1.) Step 3 RNO of EP-08 requires reset of SI (swapover).
! This is not possible until SI has been reset which the procedure does not direct. The operator must rely on the intent of the step to meaningfully accomplish the step.
2.) Step 8 of EP-06 gives no i guidance on Low Main Steam Line pressure isolation or use of steam dumps.
During the exercise, the US decided it was necessary to cooldown to recover subcooling. At this point in the exercise, subcooling was stable at about 12 F.
The EPs require subcooling to be greater than 0 F.
Even though the EPs did not direct this action, the operators began a cooldown without benefit of procedural guidance.
The US checked EP-2.2, EP-06, and EP-02 for guidance on how to conduct
' this cooldown. When the operator increased steam dump demand, a rapid cooldown resulted causing loss of NC system pressure and subcooling.
In accordance with the EPs, the loss of subcooling forced the operator to manually trip the NC pumps compounding the original event. If the EPs had been executed as intended, tripping of the NC pumps would not have been necessary. The operators preference to deviate from the guidance of the EPs is safety significant.
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The US read the entire step including all low-level actions.
The operator was expected to " remember" all low-level action steps and execute them without further direction. The operator must rely on '
their knowledge of the plant to successfully accomplish the step.
Also, miscommunications could occur.
In one instance, the US instructed an operator to verify ND alignment.
The operator checked NV and , ' reported the alignment correct. The US redirected the operator to check ND which the operator did.
The confusion between NV and ND caused the operator to make an incorrect report to the US.
Lack of ! clear and proper communications may impact the mitigation actions of [ the EPs and is safety significant.
The US also had difficulty i locating necessary data curves in the curve book.
! d.
Independent Technical Review of the EPs l The inspectors' review of the EPs found many deviations from the ERGS.
These deviations are listed in Attachment 7.
Significant deviations include, recommended step sequence rearranged, or additional steps added, several ERGS are combined into a single EP, and all the ERGS have not been implemented.
No documentation for these deviations was present.
Each of these deviations is explained in further detail below.
During this review, it was noted several EPs do not contain adverse containment values the ERGS contain. The lack of these values ! suggests multiple failures may not have been consider during l development of the EPs and is safety significant.
! (1) Rearrangement and addition of steps Review of selected EPs found numerous deviations from the preferred step sequence of the ERGS. The ERG step sequence was derived based on priorities for specific plant conditions.
Several ERG steps were not implemented in the EPs.
Revising the step sequence may impact the operators ability to properly implement the emergency procedures.
Also, steps not present in the ERGS were added to the EPs.
Aguin, these additional steps may impact the operators ability to properly implement the EPs. Rearrangement of the preftr ed step sequence and addition of steps is safety significant.
(2) Combination of ERGS The reactor trip verification actions from E-0 and reactor trip recovery actions f rom ES-0.1 were combined into AP-01, Reactor Trip. While AP-01 is technically correct, it is not in keeping with the symptom-based analysis approach of the ERGS.
The ERGS consider reactor trip a symptom of an emergency condition whether manually or automatically initiated. McGuire considers i reactor trip an expected abnormal occurance which does not l ' warrant entry into the emergency procedures.
Additionally, there is no administrative requirement for this procedure to be maintained as an EP.
The licensee's decision not to enter the EPs on a reactor trip may impact the accident mitigation strategy assumed by the ERGS and is safety significant.
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ES-0.2 and ES-0.3 have been combined into EP-1.1.
EP-1.1 is technically incorrect because it directs the operator to enter EP-16.3 if a void in the upper head is indicated.
EP-16.3 contains direction on venting of upper head area to remove any voiding. The ERG background for ES-0.2 states it is inappro-piate to conduct a head venting operation since ES-0.3 allows for upper head voiding.
The ERG background for EP-16.3 states EP-16.3 should be used only if there is a need to eliminate the void. The entry into EP-16.3 is safety significant.
(3) Unimplemented ERGS While the technical content of the ERGS may have been preserved, the overall mitigation strategy of the ERGS could be adversely affected.
Most siginficant is the lack of ERGS ES-0.0, Rediagnosis, and E-2, Faulted Steam Generator Isolation.
ECA-2.1, Uncontrolled Depressurization of All Steam Generators, is also not implemented.
The significance of not implementing ES-0.0 is that the EPs rely on alarms, status lights, and process parameter indications for operators to verify correct equipment operation or alignment.
The ERGS require the operator to conduct these verification actions by observing actual equipment conditions. These alarms, status lights, or process parameter indications may not indicate correct alignment and cause the operator to misinterpert plant conditions.
This could lead to implementation of incorrect procedures or actions for plant conditions. Use of alarms, status lights, or process parameter indication for operator verification actions is safety significant. The lack of ES-0.0 compounds this deviation because the operator has no systematic method for reanalyzing plant conditions other than reperforming the entire diagnostic.
This could lead to excessive time delays and additional errors by operators.
E-2 contains actions to identify and isolate loss of secondary coolant from a fault in any piping that connects with the secondary pressure boundary. This would include checking for multi,ple failures such as additional tube ruptures or line breaks.
Since this ERG is not implemented, the EPs must continually check for secondary faults and give direction for isolation of identified f faults.
This complicates the EPs by requiring redundant checks for secondary faults and also indicates the licensee failed to consider multiple failures.
Failure to implement all the ERGS is safety significant.
e.
Documentation McGuire has not documented the safety significant deviations between the EPs and the ERGS. The licensee stated this type of documentation is unnecessary since the individuals involved with the development of the EPs has remained constant. Also, several deviations between the PSTG and the EPs were found but are not documented. These deviations are listed in Attachment 7.
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1 Most significant is the presence of E-0 in the PSTG which is not !. present in the EPs.
NUREG 0737 and NUREG 0899 require all safety significant deviations.between the ERGS, PSTG, and EPs be documented.
. Additionally, NUREG 0800 requires an audit trail of the development of the EPs exist.
No such audit trail for the EPs' exists.
The material submitted in preparation for this inspection included a listing of. the ERG deviations from the Catawba SER.
The cover letter to this list of deviations stated the Catawba devittions should be considered approved for McGuire because the plants are of similar design and the Catawba deviations have been accepted.
No commitment by McGuire to the Catawba-deviations is present in the PGP nor has NRC accepted the Catawba deviations for McGuire.
f.
Writers Guide Comparison of the EPs against the Writer Guide found many devictions.
Steps were not in the proper format or were inconsistently formatted.
Also, art.on verbs used in the EPs sere not in the constrained language list or had multiple meanings.
Many steps lacked specificity,. did - not reference procedures to be ' used, or were redundant to other steps. These concerns are listed in Attachment 7.
Lack of consistent adherence to the guidance in the Writers Guide is safety significant.
Review of draft EPs currently under development corrects many of these concerns.
The focus to' the EPs and the operators response appears to be one of recovery-rather than mitigation. The numerous-deviations from the ERGS, lack of consideration for multiple failures, and the operators overriding concern to initiate cooldown raises serious safety questions about the EPs and the operators ability to mitigate the consequences of an accident and protect the health and safety of the public. The licensee was in the process of upgrading the EPs to correct Writers Guide and V&V identified deviations.
The licensee should also include correction of the concerns identified by the inspectors before implementing the new EPs.
The licensee was requested by NRC letter of March 21, 1989, to document the justification for the above differences and have them available on site for our inspection by June 30, 1989.
This will be IFI 369, 370/89-02-04.
No violations or deviations were identified 4.
Maintenance (62700,42700,37700) Maintenance practices have a large impact on plant operations.
The procedures for accomplishing the maintenance, training, and qualifica-tions of the personnel and the culture of the personnel and the culture of the organization all contribute to equipment availability and amount of critical personnel errors committed during maintenance activities.
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a.
Work Requests The team interviewed plant perscnnel to determine the actual process used for development and processing WRs.
The team, as a result of the interviews, observed some strengths.and weaknesses.
Strengths in the process included the keeping of an open items list for safety related equipment which can be worked when the equipment . comes down for unplanned reasons. This l'st enables backlogged work items to be performed prior to planned shutdowns.
Another positive action is the planning supervisor's tracking of the - percer.tage of WRs that are planned that have had an inspection of the effective component during the planning process.
Encouraging the planners to visit the component can improve the WR process by ensuring that limitations imposed by the conditions in the vicinity of-the equipment are considered.
Another strength is the on-shift Shift Manager processing the tagouts for the maintenance to be performed the next. shift. This allows a prioritization of tagouts, minimizing downtime of equipment important to safety.
In addition, the maintenance crews have been recently formed into specialty groups that work on specific equipment.
The mechanical maintenance group has formed a team of diesel mechanics, and a crew responsible for HVAC and cranes. This should allow the crews to be-more knowledgeable of the specific tasks they perform.
The vehicle for tracking work at the plant is the WR.
The Maintenance Management Procedure, MMP 1.0, " Definition of Work Request (Form)", Revision 15, and MMP 1.5 (not yet approved) are assigned to cover the filling out and processing of the WRs. A memo from Olmsted to Simmons in May,1987, outlined the proposed flow of the WR.
The weaknesses observed included MMP 1.5 not being issued after almost two years of development.
Clearly delineated responsibilities help to avoid problems and the chance an important function might be missed. An example of an item not picked up by groups in the planning process is the consideration of transient combustible fire loading.
The individuals interviewed while the team reviewed the planning process were not knowledgeable of where in the process the fire loading is raviewed.
Interviews with planning and safety supervisors determined a formal program to consider fire loading in the WR process does not exist.
Examples of where this could effect safety are the use of large quantities of scaffolding, or the removal and storage of combustibles such as charcoal from filter units.
An area of potential conflict is that of the Shift Manager reporting to Integrated Planning. The primary function of the Shift Manager is that of the Shift Technical Advisor.
The planning activities were assigned to make use of an available resource, but his focus should remain on the STA responsibilities.
The Shift Manager reporting to someone outside of the operations group could result in a shift in prioaities.
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Duke has a probabilistic risk assessment for McGuire.
Station personnel in operations and planning were asked if results had been.
discussed with them or if results were used in the prioritization of work.
The PRA was not used in the WR or tagging processes for determining priorities.
PRA results frequently identify systems or components that are not safety related but rank high in importance in reduction of risk to the' public or contribution to reduction of core melt frequency.
With a PRA already performed, the cost of.
disseminating this information to operations trrining or to planning.
for use in setting priorities is small, and the benefits could be .large. This lack of dissemination of PRA results is a weakness.
Interviews with the planning engineer indicated reliability data -is maintained by the specific equipment identification numbers. Common mode failure data can be missed unless failure by equipment type is evaluated. In addition, NPRDS input is a part of the WR process, but the planning engineer did not indicate NPRDS output used for planning purposes.
Using NPRDS data on equipment type in combination with site reliability data by equipment type could provide information on potential common mode failures.
b.
Backlog Status of Maintenance Work Requests The returning of equipment to service in the order of importance leads to optimization of availability of safety related equipment.
Management controls on MWR backlog, such as prioritazation of work backlog handling, are necessary in order to ensure that backlog of important equipment requiring repair does not exceed the capability - of the maintenance group while still working within a sound overtime policy.
To measure the present and future equipment availability indicators, the NRC team reviewed the MWR backlog trend and manage-ment controls for the MWR backlog.
The licensee generates a report on a monthly basis that lists number ' of MWRs that are outstanding. These numbers are categorized based on whether the MWR is outage or non-outage related, outage PM or ' non-outage PM, and also based on the length of time the MWRs have been outstanding.
The inspectors reviewed the report issued in February, 1989.
There were a total of 2684 MWRs written for the month of January 1989 of which 58 were emergency priority and 1120 were PMs.
The MWR backlog was reviewed.
The total number of outstanding non outage corrective maintenance MWRs for plant equipment greater than 3 months old was about 628, which constitutes approximately 52 % of the total MWRs.
This is at the industry average of 52%. The team noted that the maintenance superintendent was well aware of the number cf open MWRs. A chart trending the open work requests greater than one year old and greater than three months old is also attached to the report and used by the maintenance superintendent.
The team observed that there were very few i outstanding MWRs that were greater than two years old. Even though the licensee has a prioritization system that consists of only three priority levels which is less extensive than some used by other utilities, the backlog of MWRs seemed to be well controlled.
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Of the MWRs outstanding for more than one year old, the team reviewed the status of six selected MWRs that were perceived to be ' safety.
related. Of these six outstanding MWRs reviewed by the team, no - instances of inadequate or untimely corrective ac< ions were identified.
c.
Maintenance Work Performance The inspectors ' observed work performance as it was accomplished by several mechanical maintenance work crews.
The inspectors met.the workers.for their briefing by their supervisors and followed them through the process of work performance.
The observed work was performed under WRs 501439, 501353, 093108, and 092325 on the 2B diesel and auxiliaries. Weaknesses in the process were primarily related to procedures for work performance.
One crew was replacing the diesel injector "o" rings. The procedure-listed by planning for work performance encompassed work for a major teardown of the diesel heads. Prior to work performance, the inspec-tor asked the workers which procedure steps for removal of the injectors were to be accomplished. The specific steps for removal of the -injectors were identified. At the work location the inspector noted inadequate guidance had been provided to the workers prior to work performance.
The special tool needed for injector removal was not identified in the procedure as a required tool, necessitating a second trip to the tool room to ' check it out.
Steps to remove the fuel line from the fuel pump to the injector prior to injector removal were not performed prior to the first attempt at. injector removal, and had not been identified to the inspector as required steps in the removal process when asked prior to starting work. The steps were located in another section of the procedure.
The work supervisor provided direction to the workers on the use of the special tool.
l The knowledge required to perform this safety related work was beyond the " skill of the craft" and should have been directed in greater detail by the written procedure.
The practice of workers marking prerequisites ! and steps as not applicable during procedure performance can change the intent of the procedure as approved.
Housekeeping practices were observed by the inspector. Housekeeping boundaries were established prior to their being required, then violated until the time the system was broken into. This is poor , ! practice.
If the boundary is erected, the procedure should be followed. During a work break the inspector noted three crews with incomplete log-in sheets for the housekeeping boundary. Tools were in the boundary that were unaccounted for on the sheets and log theets had not been initiated for erected boundaries. The inspactor had discussions with a supervisor at the job on housekeeping techn-iques. The supervisor was aware of other techniques to help make the housekeeping easier to comply with.
The techniques included making the boundary large enough so unnecessary logging is avoided. All the tools required for the job can be brought in and logged into the boundary once, the work performed, and logged out upon removal at the end of the work. Workers were observed with tool bags out of the housekeeping area. One maintenance team member spent the majority of the activity logging " wrench in... wrench out" of the small zone that had been erected.
Inadequate training of the personnel on house-keeping techniques resulted in unnecessary utilization of a (. __ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _
. c .. . , ' . perscn that could have been providing both assistance and a second set of eyes to improve the quality of work.
' Another crew was observed to be performing work without following the . procedure. The mechanic was removing a pump assembly that was to be taken to the shop for repair. After breaking the coupling loose, the ) worker removed +he pump bolts that secure the pump bowl.
Jhen the remainder of the pump assembly could not be removed from the bowl due to lack of clearance, the worker then asked r.is co-worker to take the procedure from the work package and consult it.
Diesel Engine Cooling Water Heater Circulating Pump Removal and Replacement, MP/0/A/7400/04, dated 3/15/88, was written to accommo-date pump assembly removal by breaking loose the coupling and the pump suction and discharge line flanges and then removing the entire pump assembly, including the pump bowl. The worker was in the process of . removing the motor holddown bolts, items not addressed in the l procedure, when the inspector asked a supervisor to look at the work being performed. Later the inspector noted individuals working on a procedure change to allow the removal of the pump without the bowl.
In all of these cases, supervisors were in the area observing work in progress.
The examples of inadequate procedures for the tasks at hand, and the failure to read and follow procedures will be tracked as as apparent violation 369,370/89-02-01. In spite of the fact that i l l t . _ _ _____ ___ _ __ _ _ _ _ - _ _ - _ _ _ - _ _ _ - _ _
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house-keeping techniques resulted in unnecessary utilization of a person that could have been providing both assistance and a second set of eyes to improve the quality of work.
Another crew was observed to be performing work without following the procedure. The mechanic was removing a pump assembly that was to be taken to the shop for repair. After breaking the coupling loose, the worker removed the pump bolts that secure the pump bowl.
When the remainder of the pump assembly could not be removed from the bowl dua to lack of clearance, the worker then asked his coworker to take the procedure from the work package and consult it.
Diesel Engine Cooling Water Heater Circulating Pump Removal and Replacement, MP/0/A/7400/04, dated 3/15/88, was written to accommodate pump assembly removal by breaking loose the coupling and the pump suction and discharge line flanges, and then removing the entire pump assembly, including the pump bowl.
The worker was in the process of removing the motor holddown bolts, items not addressed in the procedure, when the inspector asked a supervisor to look at the work being performed.
Later the inspector noted individuals working on a procedure change to allow the removal of the pump without the bowl.
In all of these cases, supervisors were in the area observing work in progress. The examples of inadequate procedures for the tasks at hand, and the failure to read and follow procedures will be tracked as apparent violation 369,370/89-02-01.
In spite of the fact that the inspector asked about tagouts had the block tagout stubs. Block i tagouts normally pass the responsibility for the stubs to the super-visor.
The worker has less control over tag clearance if he is not holding the stub himself. Block tagouts prasent a greater potential for loss of control and potential personnel injury than a system where the worker holds hi s own clearance.
This potential is increased due to the practice of partial tag clearances being used for testing of components following maintenance, d.
Valve Testing program The NRC AE00 Diagnostic Evaluation team inspection conducted from November 30, 1987 to January 22, 1988 reported weaknesses in the , { licensee's stroke time testing of ASME Section XI safety related valves. As a followup, the team reviewed the records for the last four tests of 22 of Unit 1 and Unit 2 containment isolation valves.
They were reviewed for compliance to plant TS and ASME Section XI.
Additionally, the stroke time testing of six Section XI valves was observed by the team during this inspection.
The specific valves reviewed are listed in Attachment 4.
This review was conducted to assure that the valves were being tested at the required frequency j and also to assure that adequate corrective actions, including j l increase in testing frequency, were being taken by the licensee for valve failures and significant increases in stroke timing.
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During this review, it was noted that several of the valves ' selected were being tested at frequencies other than quarterly es required by ASME Section XI.
Review of the licensee's pump and valve testing program' indicated-that relief requests for all ' valves not being tested at the Section XI frequency had been submitted.
It was also noted that the prograa which was originally submitted in 1980 and 1981 for NRC approval still has not been approved.
However, there appears to have been progress made in this area during 1988 as evidenced by the licensee's most recent submittal dated October 31, 1988. This lack of program approval was also addressed by the AE00 Diagnostic Report.
The licensee is testing the valves in accordance with their program ' requirements pending NRC approval.
Review of the valve. testing determined that testing is being conducted in accordance with Section XI (other than the frequency of testing) and corrective actions. for . valve ~ failures and increased frequency of testing for valves with significant increases in stroke times are being performed as required by ASME Section XI.
e.
Diesel Fuel Oil Storage Capacity While discussing the control room pressurization issue with the NRC, the licensee stated. that a Self Initiated Technical Audit of the emergency diesel generators, conducted in May 1988, had identified-another incorrect system description in the FSAR. The FSAR descrip-tion of the diesel generators states that each diesel has an indepen-dent fuel oil storage tank that contains s'ufficient. fuel to. operate - the diesel at design load for seven days without refueling. The licensee stated that each storage tank actually contains only enough fuel to operate a diesel at design load for about four days. The' . team verified that, with a minimum supply of 28,000 gallons of fuel.. oil and a consumption of 300 gallens per hour at design load, a diesel could run for about 3.9 days.
To assess the adequacy of the amount of diesel fuel oil storage, the team reviewed the TS and the FSAR. The TS requires that'each diesel generator a ser.arate fuel oil storage system containing a minimum of 28,000 gallons of fuel.
In comparison, the team noted that the TS for Catawba, a " sister plant" of McGuire, require each diesel generator at that site to have a separate fuel oil storage system containing a minimum of 77,100 gallons of fuel. The McGuire TS cases reference Regulatory Guide 1.137, " Fuel-011 Systems for Standby i Diesel Generators," Revision 1, October 1979.
Regulatory Guide ! 1.137 describes two methods of calculation of fuel oil storage requirements. One method is based on the diesel generator operating continuously for seven days at rated capacity.
The other method allows calculations based on time dependent loads, including opera- ' tion of the engineered safety features. Applications that use the time dependent load method are to be reviewed by the NRC on a case by case basis along with the calculations. The licensee stated that time dependent load calculations have been done, with acceptable results.
However, the FSAR and SER do not indicate the use of time dependent load calculations. The team asked the licensee to promptly submit these calculations to the NR. ' . . . . .
Subsequently, the licensee conducted a self initiated technical audit which determined that the capacity of the four diesel generator fuel oil tanks did not provide sufficient capacity to run the diesel generators at rated capacity for seven days without refueling (FSAR design basis).
The TS required the minimum fuel oil volume to be 28,000 gallons per tank, which is significantly less than the volume needed for seven days of operations.
The licensee's calculation are being reviewed; followup questions and actions will follow under i seper ate correspondence.
This item is considered as an unresolved item 369, 370/89-02-02.
The licensee expressed plans to conduct additional Technical Audits, of other safety systems.
These audits can potentially be very beneficial in assuring and improving the safe design, operation, and maintenance of important systems.
f.
Engineering f The safe operation of a nuclear power plant is predicated on an l adequate design.
This design incorporates various codes and standards governing the construction and operation of the facility to j ensure the safe operation.
The design engineering function of the ! plant is carried on to ensure this design basis is maintained throughout the lifetime of the facility and is not abrogated by changes to the structure, systems and components or the manner in which they are operated.
The licensee's design engineering is done offsite, at the corporate headquarters. However, as a result of an AE00 audit conducted around December, 1987, an onsite design engineering liaison group was established in April,1988. This onsite group consists of a manager, three engineers, and one technician.
The group performs several functions: - Reviews and sponsors Station Problem Riports that need a l design change as part of the solution.
- Reviews Incident Investigation Reports that identify design as part of the problem or solution.
- Participates in onsite task forces on problems, such as silt in service water.
- Participates in the generation of a consolidated Design Basis Document for each safety related system. The current plan is to complete this effort in about five years.
' To date, the main contribution of this group has been improved liaison between the onsite departments (Operations, Maintenance) and corporate design engineering.
For example, the group recently expedited design work on an important diesel diagnostic modification that is currently scheduled for accomplishment in June, 1989.
This modification is expected to substantially improve the reliability and availability of the emergency diesel generators.
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'l Station Problem reports that indicate a need for a design change or NSM are then fowarded to the Project Services Group.
The team reviewed two NSM packages to ensure that the packages contained adequate procedures and instructions for installation, protective tagging, housekeeping, QA/QC controls, 10 CFR 50.59 review, FSAR changes, material procurement controls, and procedure updates.
One of two NSMs reviewed, MG2-0593, also verified that related procedures had been upgraded and the appropriate FSAR changes had been made.
The inspector noted, however, that the drawing which should have been removed from the master file system was still attached to the as-built drawing.
The licensee immediately corrected the package by removing the interim as-built drawing from the master file.
The team held discussions with members of the Project Services Group to verify that NSMs are screened for priority, and that scheduling is done on the basis of importance to safety.
The team noted that the licensee has a number of plant modifications scheduled for improving the reliability of safety systems. Most of these modifications are for the Control Room Ventilation System, the Emergency Diesel Generators, and the monitoring of heat exchangers for fouling. The licensee's design efforts to improve plant safety are noteworthy.
g.
Quality Assurance The licensee's TS required audits are accomplished by the corporate QA organization, which is located offsite at the corporate head-quarters.
The licensee stated that these audit teams include at least one technical expert in the area of inspection (i.e. a licensed SRO), one. member of the site Safety Review Group, and one representative from the onsite QA organization.
The onsite QA organization reports to corporate QA, and is split into four sections: verification / surveillance, technical support, QC inspection, and employee relations.
No licensed operators are included in the permanent onsite or corporate QA organization. The onsite technical support section includes two engineers.
The onsite surveillance section includes eight inspectors and a clerk.
These inspectors came primarily from the plant construction QC group, and have been given additional training, including: - Basic nuclear operator training, 37 weeks . ' - Site specific system training, 8 weeks - Specialized training; for example, chemistry, health physics, or performance The team reviewed QA surveillance inspection reports for the last year.
These reports were found to be detailed and contained many findings. The findings were adequately tracked to assure completion of corrective actions.
However, the team noted that only a few of the findings demonstrated a broad or deep knowledge of the subject areas, such as operations or maintenance.
The licensee acknowledged that there is room for improvement in performance based QA surveillance inspections.
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Overall, the team judged the QA organization to be adequate.
The use of technical experts, including SR0s, on the audit teams and the substantial training given to onsite surveillance inspectors are positive attributes, h.
Plant Status Meetings Communications or the exchange of information among members of the plant staff is important to safety.
Changes in plant status affect every department of the staff and accurate information is vital to the proper functioning of the departments and thereby, to the safe operation of the plant.
It is therefore important that communica-tions be effective, efficient and accurate.
Important information must be thoroughly disseminated through the plant organization in a timely manner.
The team attended various plant status meetings to determine whether the licensee adequately disseminated day-to-day plar.c activities and planned future activities to the applicable staff.
Status meetings are held by the Staticn Manager or his appointed designee.
Discussions of particular ongoing activities are provided by the participants of the various departments. They also identify support that is needed from other departments.
Overall, attendees were accurate and to the point on all issues, i.
DC Grounds The team noted that the plant was operating with no ground faults on the vital de electrical busses.
The control room ground fault annunciators were not in an alarm condition.
Should such an alarm occur, the alarm response procedure requires the control room operator to notify I&E technicians. The unit one operator on shift stated that vital dc bus ground faults had not been a problem in recent months.
The team interviewed I&E supervisors, who stated that in years past multiple grounds on vital de busses had been a recurring problem.
Then they obtained new portable sonic ground fault locating equipment, which enabled them to locate and repair the ground faults.
This equipment is effective in locating ground faults of 2,000 ohms or worse.
The team reviewed the I&E procedure for locating ground f aults by using this portable equipment.
The supervisors stated that, by using this equipment, the electrical technicians have been able to maintain the vital de system relatively free of ground faults.
The supervisors stated that, prior to obtaining the sonic ground fault locating equipment, a portable " light bulb method" had been used for locating grounds. They told the team that, in addition to being much less effective in locating grounds, the " light bulb method" was less safe.
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On one. occasion, their use of this method had caused a solenoid a to energize which resulted_in spurious uncontrolled operation of.
.l equipment. The team stated that NRC concerns with de grounds and J c . potential resultant spurious operation of equipment are identified in l IEN 88-36, which was issued October 21,'1988. The supervisors said ! they were aware of IEN 88-86.
The team considered.the licensee's control of vital dc bus ground. faults to be adequate. however, they alerted the I & E supervisors that a forthcoming supplement to IEN 88-86 will point out the need for even-more stringent controls of de bus ground faults.
' j.
I&E Notices Evaluation of information from outside is valuable input to the safe operation of a facility.. Various sources provide information to the - plant staff for evaluation and incorporation if applicable..This information is useful in avoiding mistakes made by others, as well as providing for increased equipment availability.
The team selected four IENs from the past 12 months to determine the adequacy of the licensee's review and their response.. Included in - these four was IEN 88-86, Operating with Multiple Grounds in Direct Current Distribution Systems. ' Additionally, IEN 87-04, Diesel Generator ' Fails Test Because of Degraded Fuel, was also examined because of the implications of the inability of the emergency' diesel' generator to operate due to severe fouling of components resulting from degraded fuel oil.
The licensee had, in all cases, reviewed and taken actions on the subject IENs in a timely manner or were taking ' action on them. As for IEN 87-04, there is a TS requirement to verify on a 31 day basis that the total particulate contamination is less than 10 mg/ liter.
This is only slightly above the total concentration of particulate that is inherently present in new fuel. The licensee has procedures, including sampling trucks before delive ry, fuel additives, and regular condensate removal, that reduce the likelihood of diesel fuel degradation.
The licensee has a formal procedure which ensures that operating experience information like IENs is effectively evaluated and distributed.
The Operational Nuclear Safety Section of Nuclear Safety Assurance coordinates.the processing of IENs with inputs from various groups including Technical / Engineering Support, Production Training Services, and Regulatory Compliance. Applicable IENs are then distributed to various station work group contacts.
The licensee has provisions for urgent notification to appropriate section heads at station level if deemed necessary.
k.
Licensee Event Reports and Fotential Reportable Events The team observed the functioning of the Licensee's program for the evaluation of abnormal maintenance events to assess it's efficiency in increasing equipment availability through correct identification of root cause and by initiating the appropriate correct'ive action.
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l The licensee initiates a PIR for the documentation of the evaluation for non-routine occurrences or situations, such as administrative or procedural deficiencies and personnel error resulting in other-than-expected equipment performance, failure to operate within established , limits or defective malfunctioning equipment. PIRs may then lead to specific NRC reporting requirements such as LERs, 50.72 reports or 10 l CRF Part 21 reports. Within the time frame of August 1987 to January 1989, the licensee reported nine LERs that were related to maintenance personnel errors.
The team reviewed three of the nine maintenance personnel related errors and noted that the appropriate corrective actions had been taken.
However, the licensee did not adequately address the root cause of the maintenance personnel related errors.
Currently, the licensee's general office is responsible for issuing LERs.
However, this responsibility will be i shifted to the Regulatory Compliance Group at the site. The licensee l is anticipating that this change will have a positive impact on the evaluation and processing of LERs.
i i 1.
Performance Monitoring Programs The following parameters were monitored and conspicuously posted at the site: forced outage rate, control room indicators out of service, reactor t( ips, outstanding work orders, and NRC violations.
The trending reports were distributed to various members of the plant management.
The Maintenance Superintendent was cognizant of the existence of the various trend reports relating to maintenance (specifically work order backlog).
He also used these trend report for planning and goal setting.
No additional violations or deviations except as noted in paragraph 4.c.
5.
Action on Previous Inspection Findings (92701, 92702) (Closed) Violation 369,370/87-26-01, Individuals worked overtime in excess
of the Technical Specification limit of 72 hours in a 7-day period without the required management apprnval, and on numerous occasions during the months of September and Octe.er 1986, March 1987, and May through July 1987, request for work hour extension were approved af ter the excessive overtime had been worked.
The inspection team reviewed work history records, training documentation, and reviewed Station Directive 2.0.10, Overtime Authorization, Rev. 4, and determined that adequate corrective actions had been taken. The actions taken to address this issue are therefore considered satisfactory and this item is closed.
(Closed) Violation 369/87-26-02, Diesel generator IA was inoperable in that it was unable to be automatically started by an initiating signal due to the lack of control power.
Further, the plant was not placed in HOT STANDBY as required.
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1 1.
The team reviewed training documentation and noted that personnel received i training on this incident during Requal Segment 5-87, and OMP 1-6, Independent Verification, was revised to more clearly give instructions to identify the steps in verifying equipment to ensure operators are on the right piece of equipment. Additionally, operators were interviewed to determine their understanding of independent verification and were noted as having a comprehensive understanding of the event and of the methodology for performing independent verification.
The inspector also noted that modifications MEVNs 1097 and 1098 are pencling implementation.
These modifications will provide an audible alarm when a diesel generator control power breaker is open.
Based on this review, this item is considered closed.
(Closed) Inspector Followup Item 369,370/87-43-01, Three procedural deficiencies were noted during the inspectors review of the Natural Circulation Cooldown Procedures.
The team determined from a review of the affected procedures that the procedural steps were adequately corrected.
This item is considered closed.
6.
Exit Interview (30703) A Pre-exit interview was conducted on March 2, 1989; with the exit J interview being conducted on March 22, 1989 with those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail the inspection results listed below.
Proprietary information is not contained in this report. Dissenting comments were not received from the licensee.
Item Number Status Description / Reference Paragraph 369,370/89-02-01 Open VIOLATION - Inadequate procedure or failure to follow procedure, paragraph 4.c.
369,370/89-02-02 Open UNR - Review licensee's calculations for determining proper fuel oil storage tank capacity, paragraph 4.e.
369,370/89-02-03 Open IFI - FSAR needs to be updated and resultant revisions should be reviewed for safety significance, paragraph 2.n.
369,370/89-02-04 Open IFI - Licensee needs to justify safety significant step deviations from owners guidlines, paragraph 3.
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. ATTACHMENT 1 Surveillance Procedures Reviewed PT/1/A/4600/03B Daily Surveillance Items, Change 0-45, change not incorp. 47 PT/1/A/4600/03A Semi Daily Surveillance, Change 0-55 PT/1/A/4700/10 Shift Turnover, Change.0-16 PT/1/A/4150/018 Reactor Coolant Leakage Calculation, Change 0-12 - PT/1/A/4200/20A Unit 1 Airlock Operability Test, Change 0-4 PT/1/A/4600/01 RCLA Movement Test, Change 0-8 PT/1/A/4450/08A Control Room outside air pressure train A, Change 0-9 .0P/0 B/6150 10 Loose Parts Monitoring system, Change 0-3 / / PT/2/A/4600/03A Semi-Daily Surveillance items, Change 0-28 PT/2/A/4600/03B Daily Surveillance Items, Change 0-27, Change 28 not incorporated PT/2/A/4700/10 Shift Turnover, Change 0-7 PT/2/A/4150/01B Reactor Coolant leak Calculations, change 0-8 PT/2/A/4200/20A Unit 2 air lock operability test, change 0-3 PT/2/A/4450/02 Un t 2 auxiliary building filtered exhaust system operability test, change.1-3 PT/0/B/4700/23 Semiinnual outside of containment locked valve verification, Rev. O PT/2/B/4700/24 Cold hutdown inside containment locked valve verification, Rev. O PT/1/B/4700/24 Cold snutdown inside containment locked valve verification, Rev. O Surveillance Reports Reviewed MC-88-27 Operation, Unit shutdown MC-88-30 Operations, equipment status NP-88-18MC Operations, Activities , MC-88-18 Operation, logs and records MC-88-10 Station Testing performance testing MC-88-11 Document control manuals MC-88-12 Operations Equipment status ' MC-88-16 Station testing, operations testing MC-88-21 Operations alarms, responses and unit operations MC-88-26 Station testing, performance testing MC-88-36 Materials, parts, and component storage MC-88-40 Special processes, personnel qualifications MC-88-41 Station testing, performance testing, NS Heat Exchangers MC-88-42 Site quality assurance document control manuals MC-88-45 Operations, equipment status MC-88-48 Document control storage administration and satellite files MC-89-2 Alarm responses and unit operations MC-88-52 Station. testing, operations testing !
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1 .... J [ ! Attachment.1
'i ' "v 4/f y Operations' Management Procedures Reviewed .OMP 1-11 Operations NSM Implementation process,.Rev. 4 OMP 4-1 Procedure writing guide, Rev. 0 OMP 2-5' Technical Specification action item Logbook Rev. 7 OMP 2-17 Tag /out review and restoration (RHR) procedure, Rev. 6 OMP 2-4 Retctor. operator-and unit supervisor logbooks,-Rev. 2 0MP 2-2 ' Shift turnover, Rev. 6 OMP 1-12 Operations communications standards, Rev 0 ' Station Directives Reviewed SD 3.1.1 Control Room Access, Rev. 1 SD 3.1.3. Action to take case of exceeding of limits,'Rev. 6-SD 3.1.5 Station operations or operating indications, Rev. 2 .S0.3.1.6 Notifying management of operating conditions, Rev. 6 SD 3.1.19 Safety tags, Rev. 20 SD 3.l.4 Conduct of operations, Rev. 20 SD 3.18-Access to containment, Rev. 9 SD 4.2.1 Handling of station procedures, Rev. 29 50 4.4.1 Processing nuclear station modifications, Rev.11 SD 4.4.2 Control of temporary modifications, Rev.9 .SD 4.7,0 Control of. maintenance program, Rev. 4 SD 5.0 1 Control of document control documents, Rev. 5 Work Requests in process / looked at Nuclear Station work request .. WR 137716 Investigate and repair cause for control room alarm "B" NC . pumps upper motor Brg. Low KC Flow (1AD6-B2) WR 096674 Perform PM oil analysis and vibration on aux. feedwater pump and turbine (unit 1) WR 096041 Perform PM oil Analysis and vibration 'on auxiliary feedwater pump and turbine I M___________.________.._._ _ _... _. _
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L ATTACHMENT 2-Control-Room Drawing Deficiencies The following control room drawing were reviewed. The revisions and applicable design change information were compared to the master files.
Drawing' Problem MC-1707-01 Portions of this drawing in the control room are illegible.
MC-1707-02 Portions of this drawing in the control room are illegible.
MC-1707-02.01' Portions of this drawing in the control room are illegible.
MC-1707-03 No problem found.
MC-1707-04 No problem found.
MC-1708-02 Portions of this drawing in the control room are illegible.
l MC-1553-2.0 No problem found.
MC-1553-1.0 Control room drawing is very messy and hard to understand i ' due to four design changes being referenced and red lined on the drawing. A new revision to this drawing should be . issued.
MC-1554-3.1' The control room had revision 10 of this drawing marked up with ' design changes ME-VN 898 and NSM 1324.
The. latest revision to this drawing in the master files is Revision 11.
MC-1556-2.1 There were two design change stamps on this drawing in the control room which had been "X"ed out and the person making this change had failed to initial and date the "X"ed information.
MC-1711-05.01 This control room drawing was completely illegible.
.MC-1711-07.01 This. control room drawing was. completely illegible. The control room had revision 28 with ME-VN 1256. The latest revision in the master files was revision 29.
MC-1711-11.02 No problem found.
MC-1711-13.01 The control room drawing was illegible.
MC-1600-1.0 No problem found.
MC-1600-1.1 No problem found.
MC-1600-3.1 The latest revision in the master files was revision 01.
The control room drawing was revision 01 with ME-VN 208 referenced.
! MC-1603-2.0 Control room copy: The design change stamp referencing ! ' ME-VN 414 was "X"ed out and initialed and dated. However, the VN was red-lined in on the drawing.
Master files ! E microfish: the VN was "X"ed out and marked "Inc" on the microfish card with no initials and date of person making the change.
Investigation determined that the VN was in fact applicable to revision 15 of the drawing.
MC-2590-1.3 Control room drawing: The design change stamp on the drawing referencing NSM 691 was "X"ed out with no initials and date of change.
Master files records indicated that the NSM did apply to the latest revision of the drawing.
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Further investigation determined that NSM 691 did not apply to this drawing but did apply to drawing 2593.
MC-2593-1.0 No problem found.
MC-2593-1.1 Master files records indicated that revision 07 with no design changes was the correct revision. The control room copy was revision 07 stamped referencing NSM 0436.
MC-2596-1.1 No problem found.
MC-1560-1.0 No problem found.
MC-1560-2.0 No problem found.
MC-1561-1.0 No problem found.
MC-1562-1.0 No problem found.
MC-1562-2.0 No problem found.
MC-1562-2,1 No problem found.
MC-1562-3.0 No problem found.
'; MC-1562-3.1 No problem found.
MC-1562-4.0 No problem found.
I MC-1563-1.0 No problem found.
MC-1564-1 No problem found.
MC-1568-1.0 No problem found.
MC-1553-3.0 No problem found.
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_ - _..__ -. . _ _. ' . . G , .- ATTACHMENT 3 Control Room Deficiencies Reviewed Work Request # Date Issued Description 135954 8/26/88 Annunciator AD-11, F-6 (control room air-conditioning "A" train chilled water temperature Hi) is in alarm with temperature at 48 degrees F. Set point is 55 Degrees F.
68137 6/18/88 Repair invalid alternate source low voltage alarm, 135799 8/20/88 Investigate and repair loss of 1A pressurizer heater bank.
137569 1/26/89 Repair annunciator 1AD9, B-7 (ice bed temperature high alarm). Alarm is in even though a'l RTDs are reading 19.4 degrees F.
Alarm set point is 25 Degrees F.
137516 1/23/89 Investigate and repair inverter 1EVIB alternate source abnormal alarm.
137439 1/18/89 Investigate and repair reason IRC-5 indication shows intermediate when valve is closed.
137420 1/15/89 Investigate and repair pen #25 on the ice condenser temperature recorder.
137248 1/23/89 Investigate and repair inaccurate service water flow indication to the containment spray heat exchangers.
137237 12/31/88 Repair position ir.dication for ICA-60 (aux feedwater) which is showing the valve 40 % open when in fact the valve is closed.
137183 12/30/88 VQ (ventilation control) annunciator for containment pressure alert does not clear when pressure is less than.2 psig.
136999 12/10/88 Valve 1KC-156 (component cooling system) is operating erratically.
, 136992 12/9/88 Investigate and repair open light for INV-167 (chemical volume control system).
136884 12/4/88 Baron addition blend flow controller occasionally works erratically.
136348 10/7/88 Control rod LoLo limit alarm cleared at 93 steps and should have cleared at 68 steps.
136195 9/21/88 Annunciator for S/I 1A not available, will not clear on the bypass panel when 1A SI is available.
135813 8/13/88 Push button for NV-1047A (chemical volume control system) will not maintain the valve open after 2 minute time delay.
135446 8/3/88 CA line 1A not available (aux feedwater system) .__. _ _. - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _
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light on the bypass panel will not clear after cycling ICA-62 and ICA-58 for performance testing.
134401 3/15/88 Investigate and repair reason for KC-51 (component cooling water system) failing to open when switch is in auto and pumps are off.
131115 4/20/87 Investigate and repair pressure switch for the oil lift pump for the main coolant pump 10.
129521 12/17/87 Investigate and repair pressure switch for the auxiliary oil pump for the "B" charging pump.
137575-1/28/89 Boric acid flow totalizer counts at a rate 3 to 4 times the actual flow.
137460 1/25/89 2CA-56 (auxiliary feedwater system) position indicates 90 % open when valve is full open.
137239 1/1/89 Investigate and repair flow indication for 2BNI pump (safety Injection system).
137238 1/1/89 Investigate and repair flow indication for 2ANI pump (safety injection system).
136357 10/11/88 2NV-267A (chemical volume control system) leaks by its seat.
136219 9/27/88 Investigate and repair cause of channel 3 (pump vibration) on the "A" NCP periodically alarming (reactor coolant system).
135995 9/22/88 Investigate and repair the cause of annunciators (D/G trouble and battery charger trouble) alarming and then clearing when the 2A D/G is started.
131031 4/27/87 PORV 2SV13 is leaking by (main steam).
131030 4/27/87 PORV 2SV7 is leaking by (main steam).
135561 7/25/88 No sound on channel 4 of the loose parts monitoring system.
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. _ _ _ ' . . ' l . ATTACHMENT 4 Valves Reviewed Under The Licensee's Valve Testing Program l The stroke time testing records for the last four tests of each of the following valves were reviewed for compliance to ASME Section XI testing requirements Vaive # Section XI Frequency Licensee testing frequency i 1-BB-1B Quarterly Quarterly " " 2-BB-1B " " 1-CF-134A " " 2-CF-134A " " 1-KC-3058 " " 2-KC-305B 1-KC-320A Shutdown " " Shutdown 2-KC-320A 1-NC-53B Quarterly " 2-NC-53B Quarterly " " " 1-NM-22AC " ' 2-NM-22AC
" 1-VP-1B During sm :m operation, when 2-VP-1B vai,c2 are cycled, and elapsed
" time since testing is >3 months.
" 1-VP-12A Also valves are not tested if
" 2-VP-12A valves are closed prior to going to a Mode where containment integrity is dequired 1-KC-338B Shutdown " " 2-KC-338B Shutdown 1-RV-33B Shutdown " 2-RV-33B Shutdown " 1-SM-3AB Shutdown " 2-SM-3AB Shutdown " Performance of the stroke time testing of the following valves was observed by the team in the control room.
2-RN-171B 2-RN-215B 2-RN-227B 2-RN-231B 2-RN-238B 2-RN-235B
- Records for these valves were not provided, valves have not been tested, per the licensee
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' . 4- , o ATTACHMENT 5 Procedures reviewed: AP/2/A/5500/01 Reactor Trip EP/2/A/5000/01 Safety Injection EP/2/A/5000/03 Steamline Break Outside Containment-EP/2/A/5000/04 Steam Generator Tube Rupture EP/2/A/5000/09 Loss of All AC-EP/2/A/5000/1.1 Natural Circulation Cooldown EP/2/A/5000/1.2 SI Termination following Suprious SI EP/2/A/5000/2.3 Transfer To Cold Leg Recirculation EP/2/A/5000/4.1 SGTR Cooldown Using Steam Dump EP/2/A/5000/16.3 Response to Void in Reactor Vessel _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _.
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ATTACHMENT 6 The inspectors conducted walkdowns of selected procedures with licensed and non-licensed operators. The operators were instructed to simulate performance of certain procedural steps.
Followup questions were asked by the inspectors to clarify ambigious steps.
During these walkdowns the following were noted: EP/2/A/5000/2.3 D.8 - Checking for NS system aligned to containment sump not for Cold Leg Recirculation alignment.
D.8 - Relies on alarm for indication of LO-LO FWST level but does not give setpoint.
D.10 - Checking for Aux Containment Spray but step states Aux Spray.
This could be confused with Auxiliary Pressurizer Spray.
EP/2/A/5000/09 C.2 - Requires check of bypass breakers open but no indication when racked out.
C.3 - Position indication for governor valves available from 0AC only.
D.13 - When asked what level they would maintain, one operator stated he would maintain 38% while another operator stated he would a maintain 35-45% control band. A range is perferred because it does not demand close operator attention as does a specific value.
D.15 - Operator stated this would be an I&E responsibility D.16.a - Operator stated there is no CR instrumentation and would have to be determined at the SSF.
D.19 - One operator did not understand what limit was te be observed or where any such limit could be found. Another operator stated ne would use limit in Table 1.
The step should specifically state which limit is to be coserved.
D.24 RNO - Has NS manually actuated but no effect until power restored.
D.27 - Requires throttle of SM PORVs but no effect until VI restored.
VI removed from emergency bus so must have non-ESF power restored. No RNO action for manual / local control.
C.5 - Startup of SSF: 1) Operator transferred power for both units to SSF. 2) Operator did not transfer power for letdown. Prevents performance of step 2.9.
3) Operator did not know Kirk-keys were located at MCCs. Operator was informed by Shift Clerk the Kirk-keys are maintained at the MCCs.
4) Procedure for startup of SSF DG was working copy.
Operator stated he would have to verify the procedure with CR before using.
5) Labeling for standby makeup pumps inconsistent.
Unit 2 labeled as " Standby Makeup Pump No. 2" _ _ __ __ -_______-_-________
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. . . . . Attachment 6
C.7 - Operator stated additional procedures are required for local S/U of EDG.
SRO in CR stated procedural steps should be sufficient.
Start of RN pump cannot be performed locally but only from CR. Procedure says to place EDG in LOCAL but can only be done from CR. One operator did not know how to determine if the EDG was in LOCAL and would have to contact the CR. Local / Remote indica-tion is available at the local EDG control panel.
C.11 RNO - instructions for manual operation of SM PORVs was inaccessible (one mounted upside down; the other sideways).
The operator could not adequately read the instructions to manually operate the SM PORVs.
No procedure for operation o# local loaders located in outside doghouse. Operator was unsure how to operate these loaders and would have to get a procedure before operating them.
12 RNO - One operator performed these actions from local controls at the CA pump room.
The operator was unaware keys were required to access these controls and did not carry the correct key. Another operator shut the valves manually at the doghouses. The operator was unaware of the other location to perform these actions.
17 RNO - These valves are located inside a locked high rad area which requires the operator to get access keys and a high range radiation detector from HP prior to entering. Also, two valves are inaccessible and require the operator to climb on piping and pipe supports to a potentially contaminated ledge then reach out to operate the handwheels. Additionally, it was difficult to locate these valves with normal plant lighting. During a loss of all AC it would be doubtful if the operator could perform this action.
EP/1/A/5000/1.1 3 - Letdown line sample done locally but step does not specify.
4 - Operator stated SD Cb from databook but did not include 100 ppm from note before step 2.
5 RNO - does not address RV not established 6 - does not specify local closure is necessary.
9 - When asked what would be used to determine letdown in service, both operators stated they would check for flow only.
When asked if they would check this flow agair.st system alignment they stated flow was the only criteria required.
10 - One operator stated he would block SI only if the plant was "under control". The operator could not adequately define "under control".
24,25 - does not state locally or give location.
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_ _ _ _ - . . < . . Attachment 6
32 - Operator stated indication is available only through the OAC Foltout page - has operator go to AP 5500/35 if SI actuates < 1955 psig.
This procedure assumes the SI is not required or inadvertent. ERGS assume any SI is valid until proven not required by the diagnostic.. EP/2/A/5000/04 D.1 procedure states "High radiation" condition but does not specify which radiation monitor alarm is to be used.
The operator stated he would use the radiation monitor trend however the procedure does not address using trend as an indic: tion.
D.2 procedural caution statement applicable if TD CA pump is the only source of feedwater. The caution may be also considered to apply if condensate pumps are available as a source of feedwater.
D.3.b.3 - requires the operator to stop the TD CA pump as necessary.
Step fails to recognize the possiblilty of restarting the TD CA pump.
D.8 procedural cautions the 100 F/hr cooldown limit may be violated. There is no 100 f/hr cooldown limit stated in the procedure.
The Technical Specification limit is 100 F in any one hour and the administrative limit is
F/hr.
The procedure should be clarified to advoid confusion with administrative and Technical Specification limits.
D.8 procedural note fails to specify both trains of Low S/G Pressure MSLI are required to be blocked.
D.8.b RNO - step states to use the ruptured S/G with the smallest apparent leakage for cooldown.
Its use should also be contingent on availability of feedwater and other support equipment.
D.11 - missing breaker label for 2 VI-1608 (B ESS Header Cont Isol Otsd) D.13 - no guidance on how to check for leaking pressurizer spray valves or PORVs. Operator stated he would stop the applicable NC pumps to check spray flow.
D.14 - step requires operator to stop SI pumps. Since one NV pump is required to remain operating, this step should be clarified to prevent the operator from removing all SI pumps from service.
D.15 RNO - actions listed across from 15.a are the RNO actions for 15.b. The RNO lacks paragraph lables and could result in the operator performing actions inappropriate to the procedure.
D.18 - caution against not aliging normal charging is contained within the RNO text. The caution should be set apart from the text so the operator will not inadvertently miss this caution.
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f:
- . . .. . . y Attachment 6
D.19 - there is no RNO for a failure of the reset action and the specific modulating valves are not identified. Operator stated he was not certain which l valves were being addressed.
D.21 RNO states to manually operate NI or NV pumps as necessary. Since one NV pump is in service (Step 16), the step should be clarified to elicit operation of.more than one pump.
l D.22 RNO - step is ambigious because there is no reference to the controls or procedure to be used.
D.23 RNO - No guidance is given. If VCT isolation valves cannot be reopened, a loss of suction to the NV pumps could result.
D.27 RNO - there is no reference to the procedure required to establish excess letdown.
D.27 RNO - actions for paragraphs a,b,c,d are on a seperate page from the A/E R contrary to the Writers Guide.
D.30 RNO - should include SM PORVs D.31 - there is no reference to the procedure required to operate the auxiliary boiler.
D.31.a RNO - the left side control compartment sightglass is unreadable.
D.31.a RNO - AS144 is inaccessible due to hot piping D.32 - step does not specify when the one hour period is to start and the equipment to be shutdown or the manner in which the equipment is to be shutdown.
EP/2/A/5000/03 Foldout - requires operator to open 2CA-6 which is normally open.
D.1 RNO - although the procedure does not specifically require local operation of the SM BYPASS valves, it was noted such actions could not be accomplished because of inaccessibility.
D.2.b - 2SMP5130 missing label plate D.3 - no label on one breaker directed by control room to be used to isolate faulted S/G valves in this step. (Panel CTR2EVDD, #6). Operator and licensed operator state S/G CF CONT ISOLATION valves could not be locally operated independently.
This would require maintenance to alter electrical jumper bars line up.
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. Attachment 6
D.3 RNO - lacks guidance on how to locally operate valves. Operator was unsure of how and received conflicting guidance from licensed operators.
D.4.b.3 - states "stop #2 TD CA pump as necessary".
This would indicate the operator can place the control switch in the STOP position. The operator must first depress the reset pushbutton before the pump could be stopped with the control switch.
D.5.b RNO - requires operator to close the associated isolation valve. Since the second valve will not close unless overridden, more specific guidance on how to shut the isolation valves is necessary.
D.10 - operators gave conflicting definitions of " normal" containment pressure and sump level.
More specific guidance should be included to clarify the intent of this step. Attention should be given to prevent excluding abnormal trends that could be within the specific guidance.
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' ATTACHMENT 7 AP/2/A/5500/01 The foldout page is not monitored during execution of this procedure.
C.3 - requires opening of generator breakers; ERGS do not contain this action.
C.4 - requires both emergency buses be energized; ERGS require at only one.
This could result in unnecessary attempts to retore electrical power to a single deenergized bus.
D 3 - requires steam dumps, atmospherics, and blowdown be closed if cooldown continues then MSIVs and bypasses; ERGS only allow for closure of steam dumps then MSIVs and bypasses.
D.6 - requires SG levels be maintained at no-load; ERGS use a control band.
This could cause the operator to be overly concerned with level control.
D.8 provides no guicance on what equipment or parameters are to be checked.
D.10 RNO - requires the master pressure controller be checked for proper operation and manually adjusted as necessary; ERGS only address PORV, spray, and heater status.
D.10 RNO - if a'PORV cannot be manually closed, requires the COPS placed in Lo Pressure mode and then close PORV; ERGS do not address this action.
D.13 - is missing prior caution on invalid instrumentation during natural circulation cooldown.
D.14 - does not address condenser not available; ERGS have steam dumped using atmospherics.
D.15, 17, 18, 19, 20, 22, 24-34 are recovery actions following a reactor trip and are not addressed by the ERGS.
These actions delay implementation of a natural circulation cooldown at step D.35.
Enclosure 1 - directs the operator to increase dumping steam if natural circulation is not verified; ERGS have this as an action for ERG step 9 (EP step D.13).
EP/2/A/5000/01 The foldout page is only reviewed; ERGS require it to be continuously monitored.
C.3 - requires the turbine throttle and governor valves shut and the generator breakers open; ERGS only require SVs to be shut.
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_ _ _ _ _ _ _ _ _ _ _ _ _ _ ._ ___ , -* . , . . . Attachment 7
C.4 - requires both emergency buses energized; ERGS only require one.
C.4 - RNO sequencing is reversed.
Operator could spend excessive time attempting to restore bus before entering Loss of All AC.
ERG E-0 steps 1-14 are immediate actions; the SI procedure rearranges these , l immediste action steps and many are subsequent actions.
D.3 - is not in the ERGS 0.3.b - appears to repeat actions in D.2.
0.4 - has local start of NI pumps based on NC pressure; ERGS require all SI pumps to be running irrespective of RCS pressure. Starting of SI pumps based on NC pressure has effect of trimming SI flow prior to meeting SI termination criteria.
D.5 performs RCP tripping; ERGS perform this action at step 21.
D.5 - does not contain an adverse containment value; ERGS do.
D.6 - combines ERG steps 7,16, and 17.
D.8 - requires throttle of RN flow and check of flow to EDGs; ERGS do not contain these actions.
D.9 RNO - requires start of AHUs but does not specify operating mode; ERGS require start in emergency mode.
D.10 - requires atmospherics to be closed also; ERGS only address MSIVs and bypasses.
D.11 RNO - has several actions not addressed by ERGS.
D.13 RNO - has COPS placed in L0 PRESS mode; ERGS do not address this.
D.13 RNO - exits to EP-02 if PORV cant be isolated; ERGS exit to E-1.
D.15 RNO - exits to EP-03; ERGS exit to E-2.
D.17 - appears to repeat action in D.15.
D.16 - checks for SG 1evel not increased uncontrolled; ERGS do not use level as j indication for SGTR.
D.19 - does not address pressurizer spray for pressure control; ERGS do.
D.19 - exits to EP-13.1 if heat sink not met; ERGS do not.
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_ - _ ___ _ - _ - _ - .______ _____ __ ___________ __________-___-______ __-___________________ __________ _____ - _ __ ' . .. . . . , . Attachment 7
D.23 - checks for PRT normal but does not specify parameters or values; ERGS do. 15 RNO - enters EP-16.3 to remove UH voids. ERGS state entery into EP-16.3 is inappropraite because ES-0.3 allows for UH voiding.
16 - ES-0.3 cautions and notes are missing.
16.d - checks for reinitiation of SI; ERGS do not address this.
16.d - RNO directs to adjust charging and letdown to recover subcooling; ERGS only address dumping steam.
18 - states to maintain cooldown rate < 100 F/hr; ERGS specify cold leg cooldown rate.
21.c - removes CLA from service; ERGS do this when SI system requirements are checked.
23 - states to maintain 120 gpm letdown flow; ERGS state to maintain RCS inventory constant.
24 - uses T-ave for RCS temperature; ERGS specifically state this is not accurate because of inadequate flow through the RTD manifolds and hot / cold leg ) indications should be used.
32.a - RNO is missing; ERGS specify waiting until UH temp is reduced.
32.d - RNO enters EP-16.3; ERGS do not address entering EP-16.3 EP/2/A/5000/1.2 Entry conditions indicate general SI termination, not spurious.
6 - checks subcooling and pressurizer level; ERGS do not.
6 RNO - requires manual SI and exit to EP-01; ERGS do not manual SI and exit to E-1. (Ref. ES-1.1 step 8) 9 - does not require phase B to be reset; ERGS do.
10 - requires verification of VI without any acceptance criteria.
12 - does not specify the charging flow rate; ERGS do.
! 18 - does not address non-emergency buses: ERGS do.
20-46 - are not ERG steps. (except 34) EP/2/A/5000/09 i i - _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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. , .
. ' . Attachment 7
D.3 and D.4. are delayed to subsequent actions; ERGS are immediate actions.
D.3 - addresses PORVs shut; ERGS address isolation of flowpaths including PORV block valves.
D.4 - RNO directs start of TD CA pump but does not specify method.
D.6 - removes the sequencer from operation; ERGS have equipment placed in PTL.
This allows for autostart of SW (RN) pumps and re-loading of 480V buses to assist in plant evaluation.
EP does address restart of RN pumps but doe, not address loading of 480V buses.
D.10 - does not address main feed isolation; ERGS do.
D.12 - uses SG 1evel increasing uncontrolled as an indication of ruptured SG.
ERGS state level is not accurate because AFW has not yet been throttled.
D.12 - does not use SG blowdown as indication of ruptured SG; ERGS do.
D.15 - does not require local monitoring of batteries.
D.18 - caution about injection of N2 into NC not present.
l EP/2/A/5000/04 ERG step 1 is not included in the EP. This step is included in the event of multiple failures or misdiagnosis by the operator.
D.2 - does not require S/G blowdown isolated; ERGS do 0.3 - contains ACC value; ERGS do not D.6 RNO - requires verify faulted S/G steam lines isolated; ERGS transistion to E-2 to perform S/G isolation functions.
D.6 RNO - requires manual isolation if PORV cannot be closed; ERG transitions to ECA-3.1 if PORV cannot be isolated.
EP does not contain this guidance.
, D.7 - This action is delayed until ERG step 35. Attempting to establish forced cooling may delay prompt implementation of other mitigating actions. This step also requires the operation of two (2) NC pumps where the ERG only require one.
The additonal NC pump will add heat in excess of that assumed by the ERG and could result in a negative effect on mitigation actions.
D.9 - missing ERG caution that step 8 should be completed before continuing.
, l ERG step 11 is not implemented in the EPs. This continous action step provides guidance on how to restore power if lost so plant cooldown can be expedited.
D.12 - ERG requires maximum spray flow be used to depressurize as rapidly as possible.
EP does not direct use of maximum spray flow which could cause , l -______ -
F~:
- . , < .
. , . Attachment 7
unnecessary loss of NC system inventory during a tube rupture. The EP contains an ACC value; ERG does not D.13 - addresses leaking spray valves; ERG does not.
Step does not give sufficient criteria to determine if PORV is leaking or action to be taken if l PORV leakage is suspected. Step does not transistion to ECA-3.1 if PORV cannot ' be isolated.
D.14 - requires feed flow actually delivered to S/Gs; ERG requires feed flow only be available not actually delivered.
This could result in excessive feeding if a faulted S/G is used for cooldown.
DEVIATIONS BETWEEN EPs AND ERGS EP/2/A/5000/04 D.1 RNO - not structured as IF-THEN-ELSE format; PSTG is D.2.a RNO - states close valves on non-ruptured S/Gs; PSTG states MSIVs and bypasses.
D.2.b RNO - states to verify SM PORVs opening; PSTG states to manually operate.
' D.2.c RNO - allows for use of manual loaders before shut block valves; PSTG does not contain this allowance.
D.3 RNO - states not to feed faulted S/Gs; PSTGs do not contain this statement D.4 - step has bullet for all S/Gs pressurized; PSTG has "and" D.5 - maintain S/G 1evels at no-load; PSTG states near no-load, r f a RNO - addresses block viv shut due to leakira PORV only; PSTG addresses tau-'.y PORVs or block vivs D.7 caution - not present in PSTG D.7.a RNO - does not address establish conditions for pump restart; PSTG does
D.7 RNO part 2) confusing w/part 3) 0.8 - note about concurrently performing 8-13 not present in PSTG.
D.9 thru D.11 - steps rearranged from PSTG D.12.b - states pzr level > 95%; PSTG state < 95% D.12.b - checks for ruptured S/G 1evel constant; PSTG does not _____ -___-_______-____ _ - _ _ _ -
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. .w Attachment 7
I D.12.b - does not check for NC pump running; PSTG does D.12.b RNO - if no NC pump running, PSTG checks RVLIS UH and pressurizer response and if abnormal goes to FR-I.3; EP does not address this action 0.14 - caution on overfill of ruptured S/G not present in PSTG D.19 - not addressed-in PSTG (PSTG step 22?) D.26 - establishment of KC not present in PSTG EP/2/A/5000/01 C.2 - checks for both RTBs and RBBs open; PSTG only checks for RTBs open C.4 - checks for both E busses energized; PSTG only checks for at least one energized 0.4 RNO - allows operator to attempt to restore power; PSTG only allows entry into Loss of All AC C.2 RND'- check of OAC TS program or attachment not in PSTG D.11 RNO b. - EGP refers to FR-Z.1; EP does not D.16 - PSTG specifies non-faulted S/G; EP does not D.18.a - S/G NR level setpoint has ACC vaule; PSTG does not give ACC EP/2/A/5000/1.1 1.b - states start at least one NC pump; PSTG states start one NC pump 6 - this step is not in the PSTG 7 - caution is not present in the PSTG 11 - PSTG states cooldown rate in the cold legs < 50F/hr l 13 RNO - PSTG does not allow for establishment of letdown, only addresses use of pzr PORV 24 - PSTG states temperature of 425 F EP states 350 F.
I 32.c - checks NC loop temperature < 160 F; PSTG does not address this Foldout - requires entry into AP/2/A/5500/35 if SI actuated < 1955 psig. This procedure assumes SI inadvertent.
ERGS structure to enter EPs on any SI irrespective of pressure.
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. - ____.__ __ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ 5 - , , l-- , , . ATTACHMENT 8 ACRONYMS AE00 - ANALYSIS AND EVALUATION OF OPERATIONAL DATA AP - ABNORMAL" PROCEDURE ASME - AMERICAN SOCIETY OF MECHANICAL ENGINEERS , k CFR - CODE OF FECERAL REGULATIONS DC - DIRECT CURRENT ECA - EMERGENCY CONTINGENCY ACTION EP - EMERGENCY PROCEDURE ERG - EMERGENCY RESPONSE GUIDELINES FSAR - FINAL SAFET ANALYSIS REPORT HEPA - HIGH EFFICIENCY PARTICULATE ABSOLUTE HP - HEALTH PHYSICS 'HVAC - HEATING VENTILATION & AIR CONDITIONING
IFI - INSPECTOR FOLLOWUP ITEM I&E - INSTRUMENT & ELECTRICAL IEN - NRC INFORMATION NOTICE LCO - LIMITING CONDITION FOR OPERATION LER - LICENSEE EVENT REPORT i LOCA - LOSS OF COOLANT ACCIDENT M2VN - MECHANICAL ENGINEERING VARIATION NOTICE MMP - MAINTENANCE MANAGEMENT PROCEDURE i MP - MAINTENANCE PROCEDURE MWR - MAINTENANCE WORK REQUEST NC - NUCLEAR COOLANT SYSTEM ND - RESIDUAL HEAT REMOVAL SYSTEM NPRDS-NUCLEAR PERFORMANCE REPORTING DATA SYSTEM NUREG-NUCLE 4" REGULATION NSM - NUCLEr STATION MODIFICATION NRC - NUCLEAR REGULATORY COMMISSION i NV - CHEMICAL VOLUME CONTROL SYSTEM OATC - OPERATOR AT THE CONTROLS OSTI - OPERATIONAL SAFETY TEAM INSPECTION OAC - OPERATIONAL AID COMPUTER PROCEDURE GENERATION PACKAGE PGP - POTENTIAL INCIDENT REPORT PIR - PM - POST MAINTENANCE PRA - PROBABILISTIC RISK ASSESSMENT PSTG - PLANT SPECIFIC TECHNICAL GUIDELINES PERFORMANCE TEST PT - QA - QUALITY ASSURANCE QUALITY CONTROL QC - RESPONSE NOT OBTAINED RNO - RO - REACTOR OPERATOR SAFEY INJECTION SI - SENIOR REACTOR OPERATOR SR0 - SHIFT SUPERVISION SS - SHIFT TECHNICAL ADVISOR STA - ! _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _
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,,. ' . Attachment 8
TS - TECHNICAL SPECIFICATIONS UNR - UNRESOLVED ITEM US - UNIT SUPERVISOR WOG - WESTINGHOUSE OWNER GUIDE WR - WORK REQUEST f I
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