ML20151E037
| ML20151E037 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 07/08/1988 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20151E027 | List: |
| References | |
| 50-416-88-09, 50-416-88-9, NUDOCS 8807250340 | |
| Download: ML20151E037 (41) | |
See also: IR 05000416/1988009
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ENCLOSURE
SALP REPORT
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
INSPECTION
REPORT NUMBERS
50-416/88-09
System Energy Resources, Inc.
Grand Gulf
November 1, 1986 through April 30, 1988
8807250340 88070s
PDR ADOCK 05000416
O PDC
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-I. INTRODUCTION
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The : Systematic Assessment of Licensee Performance (SALP) program is an
integrated NRC <taff effort to collect available observations and data on
a periodic basis and to evaluate licensee performance based upon this
information. The SALP-is supplemental to normal regulatory processes used
to ensure compliance with NRC rules and regulations. The SALP is intended
to be sufficiently diagnostic to provide a rational basis for allocating
NRC resources and. to provide meaningful guidance to the licensee's
management to_ promote the quality and safety of plant construction and
operation.
An NRC SALP Board, composed of the staff members listed below, met on
June 13, 1988, to review the collection of performance observations and
data to assess the licensee performance in accordance with the guidance in
NRC Manual Chapter 0516, "Systematic Assessment of Licensee Performance."
A summary of the guidance and evaluation criteria is provided in Section
II of this report.
This report is the SALP Board's assessment of the licensee's safety -
performance for the Grand Gulf facility for the period November 1,1986
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through April 30, 1988.
SALP Board for the Grand Gulf facility:
L. A. Reyes, Director, Division of Reactor Projects (Chairman)
A. F. Gibson, Director, Division of Reactor Safety, RII
J. P. Stohr, Directer, Division of Radiation Safety and Safeguards, RII
0. M. Verrelli, Chief, Projects Branch 2, ORP, RII
E. G. Adensam, Director, Project Directorate II-1, NRR
R. C. Butcher, Senior Resident Inspector, Grand Gulf, ORP, RII
L._L. Kintner, Senior Project Manager, Project Directorate 11-1, NRR
Attendees at SALP Board Meeting:
K. D. Landis, Chief, Technical Support Staff (TSS), DRp, RII
H. C. Dance, Chief, Project Section 2B, DRP, RII
L. P. Modenos, Project Engineer, Project Section 28, DRP, RIl
J. L. Mathis, Resident Inspector Grand Gulf, ORP, RII
II. CRITERIA
Licensee performance is assessed in certain functional areas depending
upon whether the facility has been in the construction, preoperational, or
operating phase. Each functional area normally represents an area which
is significant to nuclear safety and the environment and which is a normal
programmatic area. Some functional areas may not be assessed because of
little or no licensee activities or lack of meaningful observations.
Special areas may be added to highlight significant observations.
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'One or more of the following evaluation criteria were used to assess each
functional area; however, ~ the SALP Board is not limited to these criteria
and others may have been used where appropriate.
A. Mar,agement involvement in assuring quality
B. . Approach to the resolution of technical issues from a safety
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C. Responsiveness to NRC initiatives
10. Enforcement history
E.. Operational and construction events (including response to, analysis
of, and corrective actions for)
F. Staffing (including management).
G. . Training.and qualification effectiveness
Based upon the SALP Board assessment, each functional area evaluated is
classified into one of the three performance categories. The definitions
of these performance categories are:
Category 1: Reduced NRC attention .may be appropriate. Licensee
management attention and involvement are aggressive and oriented
toward nuclear safety; licensee resources are ample and effectively
used so that a high level of performance with respect to operational
. safety or construction is being achieved.
Category 2: NRC attention should be maintained at normal levels.
Licensee management attention and involvement are evident and are
concerned with nuclear safety; licensee resources are adequate and
are reasonably effective so that satisfactory performance with
respect to operational safety or construction is being achieved.
Category 3: Both NRC and licensee attention should be increased.
Licensee management attention and involvement is acceptable and
considers nuclear safety, but weaknesses are evident. Licensee
resources appear to be strained or not effectively used so that
minimally satisfactory performance with respect to operational safety
or construction is being achieved.
The functional rea being evaluated may have some attributes that would
place the evaluation in Category 1, and others that would place it in
either Category 2 or 3. The final rating for each functional area is a
composite of the attributes tempered with the judgement of NRC management
as to the significance of individual items.
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The SALP Board may also include an appraisa' of the performan'ce trend of a
functional area. This performance trend will only be used when both a
n definite trend of performance within the evaluation period is discernable .
and the Board believes that continuation of the trend may result in a
change of performance level. The trend, if used, is defined as:
Improving: Licensee performance was determined to be improving near the
close of the assessment period. -
Declining: Licensee performance was determined to be declining near the
'close of the assessment period.
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III. SUMMARY OF RESULTS
A. Overall Facility Performance
The responsibility to maintain and operate the Grand Gulf Nuclear
Station-was turned over to System Energy Resources, Inc. (SERI) from
Mississippi Power and Light (MP&L) on December 20, 1986 following NRC
review and approval. Middle South Utilities, Inc., announced the
formation of SERI on July 28, 1986, in order to bring about a
concentration of leadership, management, financial, engineering and
other technical talent to place strong management attention in
operating a nuclear facility.
On May 9, 1988, SERI announced plans to assume management and
operating responsibility for the Middle South Utilities (MSU) nuclear
operations. SERI is a wholly-owned subsidiary of MSU. Under the
plan, SERI will assume operating responsibility for MSU's four
nuclear units: Arkansas Nuclear One, Units 1 and 2; Waterford 3 and
Grand Gulf Unit 1. All necessary regulatory approvals and corporate
arrangements are expected to be completed by December 31, 1988.
Overall performance has shown a measurable improvement. Continued
superior performance was noted in the functional areas of Radio-
logical Controls, Security and Outages. Significant improvement was
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evident in the areas of Plant Operations, and Fire Protection result-
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ing in a SALP rating change from Category 2 to Category 1. Emergency
Preparedness and Maintenance areas were rated Category 2 with an
improving trend and the licensee is encouraged to maintain their
level of effort in these areas. One new area rated was Engineering
Support which was rated Category 2. There were no areas rated as
Category 3. During this evaluation period there were approximately
the same number of inspections as the previous SALP period including
three special inspections: Probabilistic Risk Assessment, Environ-
mental Qualification and Emergency Operating Procedures. There were
22 noncompliances identified versus 38 noncomoliances for the previous
SALP period. There were no escalated enforcement issues.
A concern noted through several functional areas is related to the
quality and adherence to procedures. Specifically, failure to follow
procedures and failure to establish acceptance criteria and tolerance
in the surveillance area,
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The licensee has initiated several organizational changes to
distribute workload, censolidate and strengthen functions to effect
improved performance. Organizational changes included new positions
for the manager of emergency preparedness, a site controller and an
administrative assistant reporting to the general manager. The
licensee has attempted to upgrade the operational knowledge of all
key personnel. Key Managers / Superintendents currently maintain or
previously held Senior Reactor Operator licenses.
SERI's college degree program was started in September 1985 and
brings the college faculty to the job site. The first person to
graduate from this program, a supervisor in the Training Department,
received a Bachelor of Science degree in Nuclear Engineering
Technology.
As a result of an Institute of Nuclear Power Operations (INPO) audit
of September 1987, the licensee received a rating of exemplary overall
performance. Industry standards of excellence were met in many areas
and no significant weakness were noted. Full INP0 accreditation was
achieved.
Unit 2 construction activities are essentially stopped. Therefore,
Unit 2 was not evaluated for this assessment period.
B. The performance categories for the current and previous SALP period
in each functional area are as follows;
May 1, 1985 - November 1, 1986 -
Functional Area October 31, 1986 April 30, 1988
Plant Operations 2 1
Radiological Controls 1 1
Maintenance 2 2 Improving
Surveillance 2 2
Fire Protection 2 1
Emergency Preparedness 2 2 Improving
Security 1 1
Outages (includes refueling) 1 1
Quality Programs and 2 2
Administrative Controls
Affecting Quality
Licensing Activities 2 2
Training 2 2
Engineering N/A 2
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IV. Performance Analysis
A. Plant Operations
1. Analysi s .
During this assessment period, inspections were performed by the
resident and regional inspection staffs.
Overall facility operation has shown definite improvement. The plant
scram rate was 0.5 per 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> critical at power (i.e., >15%)
versus approximately 2 scrams per 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> critical for the previous
SALP period. The overall Nuclear Industry average is slightly less
than 1.0 scr m per 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> critical for this period. Marked
improvements have been identified in the reduction of scrams at
power. All five scrams from power were the result of equipment
problems, but the root cause for some of the scrams indicates they
could pessibly have been prevented. For example, a scram on August 6,
1987, resulted from moisture condensation in a switchyard control
cabinet creating a short in a lockout relay resulting in the
inadvertent opening of two switchyard breakers. A reactor scram on
March 15, 1988, resulted from a loose screw in a terminal box that
had deenergized the Division 1 solenoids on 29 scram pilot valves,
causing 29 control rods to insert (scram) when a surveillance was run
on Division 2 and causing a reactor scram on reactor vessel low water
level. Four scram signals received while in shutdown indicates that
improvements are needed in management controls during shutdown
operations. Of the four scrams while non-critical, two were due to
personnel error ard one was due to procedural error. The fourth
scram was due to equipment failure. A scram reduction program
initiated in early 1985 has been effective. Ten scram reduction
program items, six of which were hardvare changes, were completed
this SALP period. The plant set a boiling water reactor world record
of a 171 day run for the second fuel cycle.
The licensee has initiated a review board consisting of the
Manager-Plant Maintenance, Manager-Plant Operations and Manager-Plant
Support to meet and review each incident involving a personnel error
and provide a written report of their findings and recommendations to
the General Manager, Some plant management personnel recently
completed a one week INPO training course entitled Human Performance
Evaluation Systems Training. Since human performance problems are a
major contributor to significant events, programs that reduce the
occurrerce of human performance problems contribute significantly to
increased safety. This program has been termed the Near Miss program
because that is the essence of the program, to identify near miss
situations that could affect plant operability or safety. The
employee is provided p'otection from reprisal for incidents in order
to encourage reporting of near miss situations.
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To improve the actual operational experience level of other
organizations, several licensed operators have been temporarily or
permanently assigned to other areas. Some cross utilization of
licensed operators was as follows: In July 1985, a Senior Reactor
Operator transferred to the Training department and returned to
Operations in July 1987. In December 1987, a Reactor Operator
transferred from Operations to the Training Department. In
February 1988, a Senior Reactor Operator and a Reactor Operator
transferred from Operations to the Training Department. In July
1987, a Senior Reactor Operator transferred to the Outage Scheduling
Department to help prepare for the second Refueling Outage that
started November 1987. He transferred back to Operations in January
1988. In March 1987, a Reactor Operator transferred to Quality
Programs and returned to Operations in Fabruary 1988. In January
1988, another Reactor Operator transferred to Quality Programs. The
rotation of these individuals enhanced the operational experience
level of the various support groups.
The licensee is responsive to NRC conorns that have been ider.tified
to them. An example of this is an issue regarding operations
personnel potentially having restricted access to some areas of the
plant during emergency events. A comment to this effect was made
during the special operational safety inspection on Probabilistic
Risk Assessment. In November 1987, a standing order was issued
requiring four operators plus the fire brigade leader to carry
security series keys that a? low passage in case of key card fa' lures.
Previously, only the fire brigade leader had carried a security
series key.
The licensee is committed to improving operations. During the second
refueling outage a control room redesign was incorporated. The Shift
Supervisor's office is now accessible thru a glass window arrangement
such that people processing work authorizations now enter thru a door
i outside the control room. This limits control room congestie and
l noise. The Shift Superintendent's desk and the control room
l operator's desk were both elevated to enhance control room
l visibility. The simulator has also been updated to reflect the
! actual control room configuration. A set of management standards was
developed to be used in the day-to-day execution of operations
duties. These management standards define such things as control
room command ano organization, communications, thif t turnover, and
conduct of rounds. Another initiative just getting started is the
movement of the Shift Technical Advisors from the Technical Support
section to the Operations section. The intent is to send those Shift
Technical Advisors that volunteer through the Senior Recctor Operator
program. This will increase the number of available Seniar Reactor
Operators who hold a college degree. Additionally, the Operations
Suerintendent has four licensed Senior Reactor Operators as
assistants in addition to those on shift. NRC observat'ons confirmed
that the plant has had an ef fective claanliness and nousekeeping
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program with periodic scheduled cleanup days where all personnel are
. involved. Control room decorum has improved over the previous SALP
period. The conduct of shift personnel in the Control Room is
professional. The licensee has an active program to reduce the
number-_of illuminated annunciators during operation. The number of
lit annunciators has been drastically reduced since initial startup.
The licensee's goal is to achieve a black boar'd.during power operations
The NRC also observed a high morale of plant personnel which reflects
positive management involvement in daily activities. Management has
also strived to provide operators with essential tools for the conduct
of routine operations, such as up to date ari legible drawings and
procedures. The plant operating procedures are clearly written
'and thorough. There has been no turnover of licensed personnel.
During this evaluation period 39 LERs were submitted by the licensee.
The LERs were evaluated by the NRC staff to determine the event
cause. The number of LERs caused by personnel errors was 24 for this
SALP period as opposed . to 59 during the previous 'SALP period.
Although there was a reduction in the number of LERs, personnel error
still stood out as the number one root cause of LERs and should
receive. increased management attention.
The LERs adequately described all the major aspects of the event,
including all component or system failures that contributed to the
event and the significant corrective actions taken or planned to
prevent recurrence. The reports were thorough, detailed, and
generally well written and easy to understand. The quality and
preciseness of the information in the LERs was high. The narrative
sections typically included specific details of the event such as
valve identification numbers, model numbers, number of operable
redundant systems, the date of completion of repairs, etc., to
provide a good understanding of the event. The root cause of the
event was clearly identified in most cases. Previous similar
occurrences were properiy referenced in the LF.Rs as applicable except
for two LERs which required resubmittal. lhe licensee updated
' several LERs in the assessment period. The updated LERs provided new
'information, denoted by a vertical line in the right hand margin, se
that the new information could be easily determined by the reader.
We note that Grand Gulf updated LERs when the corrective actions
listed in the original LERs were completed.
There were two violations identified in the Ooerations area The
decreased number of violaticos indicate a significant improvement
over the previous SALP period in which ten violations were
identified, This improvement reflects 'a increased operational
experience of the operations personnel and a dedicated effort by
operations personnel and management to improve performance. The two
violations do not indicate a programmatic deficiency but are in the
area of failure to follow procedures which needs more attention.
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a. . Severity Level IV Violation for failure to follow procedures to
properly store -nitrogen bottles within containment.
(416/88-01-01)'
tn Severity Level V Violation for failure to follow procedures and
" implement coldfweather oreparations.
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(416/87-29-02)
2. Conclusion
Category: 1
3. Recommendations
A high level cf performance was achieved in this area. The NRC
staff resources applied to the routine inspection program should.
be' reduced.
B. Radiological Controls
1. Analysis
During this hssessment pericd, inspections were performed by the
resident and regional inspection staffs. Eight routine radiation
protection, radwaste and chemistry inspectio7s were performed durino
the _ assessment period including one confirmatory measurements v'
inspection. One special inspection was performed in response to
hydrogen burn in the charcoal beds of the offgas adsorber system.
The licenset's health physics staffing levels were appropriate and
compared well to other utilities having a facility of similar size.
The licensee has budgeted 70 health physics positions , 68 of which
were filled as of April 30, 1988. During the assessment period, the
licensee added three new supervisory positions for dosimetry
processing, dosimetry administration, and instrumentation. The
licensee added an additional health physics crew to the rotating
shift schedule to allow a dedicated week for training purposes in the
b rotation. The plant Health Physicist / Technical Assistant osition
also-became a permanent staff position during the assessment period.
An adequate number of ANSI qualified licensee and contract health
physics technicians were available to support routine and outage
operations. The licensee did not rely on contract personnel to
support routine operations or supplement technical capabilities.
While the licensee was able to obtain all of the contract personnel
needed, the licensee has recognized the shortage of health physics
contract support help available in the industry. The licensee is
participating in a Middle South Utility System Task Force
investigating ways to meet health physics manpower needs for the
future.
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The knowledge and experience 1.evel ' of the site health physics
personnel were good. The health physics personnel have an effective
training program. The licensee received Institute of Nuclear Power
Operation-(INPO) accreditation of their Health Physics and Chemistry
Training programs in June 1987.
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The radiological effluent and radwaste staffing levels were adequate
with a quality training program that is presented by knowledgeable
and well- qualified instructors. The chemistry personnel have strong
'and capable managers and supervisors with a stable and espable staff
of technicians.
The performance of the health physics personnel in support of routine
. operations and outages was good. No substantive issues were
identified in this area. Only one radiation protection related
violation (for failure to follow procedures) was identified during
the assessment period and that violation was identified by the
licensee.
Management support and involvement in matters related to radiation
protection 'and radwaste control was very good as evidenced by
approval of the newly created and filled health physics positions.
Management support for ALARA and radioactive protection programs
included the procurement of equipment such as a cavity dall
decontamination device, remote closed circutt TV's, and computer
programs developed to track calibration ad inventory of portable
radiation survey instruments. The pie is radiation protection
manager received the support of other plant managers in implementing
the radiation protection program.
Resolutions of technical issues by the healtL physics personnel was
good as evidenced by their actions associated with defective
thermolumin'escent dosimeters (TLDs). The health physics personnel
. identified a problem with vaporization of the TLD material,
discontinued use of their own system and obtained contract TLD
service while investigating the problem. They identified the source
of the problem and modified the readout temperature parameters as
recommended by the TLD vendor. The licer.see returned their TLD
system ' to service after verification that the problem had been
corrected. The lice.1see also provided periodic updates to NRC staff
on the progress of its corrective actions.
Responses to NRC initiatives were conducted in an effective and
acceptable manner as evidenced by the licensee's willingness to
improve plant fuel handling procedures for radiological safety
considerations and improve the bases for dosimetry programs through
additional energy spectrum measurements and dose algorithm documenta-
tion. The licensee revised refueling procedures to address ALARA
considerations and communication requirements for haalth physics and
operations personnel. The procedures require operations personnel to
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notify health physics personnel prior to movement of the first' fuel
bundle from the reactor -core and to restrict -the movement of fuel
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- bundles over the downcomer -region except to directly enter or exit
the-cattle chute.
The . licensee's ' radiation . work permit and respiratory protection
programs were found :to be satisfactory. The number of Personnel
~ Contamination Reports declined during the assessment period. The
licensee ended.1986 with 246 personnel contamination reports, 168 cf
which included skin contamination. In 1987, the personnel
contamination reports decreased to 156 of which 96 included skin
contamination for decreases of 63% and 57% respectively. As of
April 30, 1988, the licensee had documented 31 cases of personnel
contamination which included 14 cases of u skin contamination. The
licensee has developed procedures addressing hot particles, however,
hot particles were not an exposure problem during the assessment
period. The number of personnel having a positive indication of
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internal contamination decreased during the assessment period. In
1986, the licensee documented 15 measurements of persons having more
e that 1 % maximum permissible organ burden (MP0B) and less than 5%
MP0B and only 1 person within that range in 1987, and 1 person
through April 30, 1988. The licensee did not have any whole body
measurements in excess of 5% MP0B in 1986, 1987, or through April 30,
1988. The licensee attributes the reductions of positive
measurements to improved training programs and improved worker
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experience.
At the end of 1986, the licensee had 31,166 square feet (f t 2 ) of
contaminated area which represented 6.3% of the radiologically
controlled area of the plant. The licensee had reduced t..e
contaminated area down to 19,125 f ' or 3.1% of the . radiologically
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investigating contamination sources and increased ef ficiency of the
assigned decontamination crew ere factors which have helptd the
licensee reduce the contamination area.
The 1986 and 1987 cumulative radiation exposures were 436 and
399 person-rem, respectively. This compares favorably to the
national average exposures of 622 person-rem per unit in 1986, and
521 person-rem per unit in 1987, at other BWR facilities. The
licensee als: met their ALARA goals of 600 person-rem in 1986, and
425 person-rem in 1987. Through the end of April 1988, the licensee
had accumulated 64 person-rem and had established a person-rem goal
of 160 person-rem in 1988 when no refueling outages are planned. The
licensee attributes the success in meeting its 1987 goal to better
planning and involvement between the plant groups. The licensee
added two ALARA Specialists to its personnel during the assessment
period and utilized the experience gained form the first refueling
outage in planning and determining person-rem per task. The ple.rt
personnel improved their efficiency at certain tasks as h unstrated
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by an' Intermediate Range Monitor (IRM) replacement job that was
c performed in the first refueling outage-- in 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> with
0.46 person-rem and repeated in the second refueling outage at
slightly elevated dose rate fields in -only 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> with
0.11 person-rem. Improvements.in radiation dose exposures were noted
in auxiliary. and feedwater control valve work, tne installation of
temporary shielding and routine fuel movement activities.
During 1986, the licensee disposed of 17,564 cubic feet (ft ) of
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solid waste containing 1360 curies. The volume of solid waste
decreased in 1987 to 13,833 ft3 while the activity increased to
1663 curies. As of April 30, 1988, the licensee had shipped 8895 ft3
of solid waste containing 196 curies. The licensee experienced some
leakage in one fuel bundle in 1987, which caused the activity of the
radioactive waste to increase. The deteriorated fuel was removed
during the second refueling outage. The licensee has a waste volume
reduction plan which includes surveys, sorting, and segregation cf
waste into clean or contaminated waste for release to burn. The
licensee placed emphasis on reducing radioactive waste volume by
limiting the material entering the radiological controlled area.
Liquid and gaseous radioactive effluents were within the Technical
Specification l i mi t:, and in compliance with 40 CFR 190 limits for
radiation dose and radioactivity concentration in effluents. In
general the total amounts of radioactive effluents has increased over
the past three years; however, the liquid and gaseous releases were
less . than the average annual releases reported by four Region II
plants of similar size and type for 1986. There were no unplanned
liquid or gaseous releases above limits required to be reported to
the NRC during the evaluation period. Annual effluent release and
dose summaries for 1985-1987 can be found in Section V.K.
A confirmatory measurement inspection conducted during February 1987,
indicated agreement for all measured isotopes. A simulated liquid
waste sample which contained H-3, Sr-89, Sr-90, and Fe-55 was
provided during May 1987. The licensee successfully analyzed the
liquid spike itnd all results compared favorably (ir agreement) with
the NRC values using the NRC established comparison criteria.
A special inspection was conducted during March 1988 in response to a
hydrogen burn in the off gas system. The inspection determined that
the system integrity did not appear to have been compromised and that
no radiological effluent limits were exceeded during the event. The
cause was attributed to system design defh ancies combined with
temperature monitoring equipment malfunctioning. The licensee
responded promptly and correctly in identifying the problem and
taking corrective actions.
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The- plant made significant improvement in its chemistry control
program in the last year. These advances were attributed to strong
cnd . knowledgeable managers and supervisors who were hired
approximately- two years ago. The plant had been plagued by
microbiological induced corrosion problems throughout its service
water systems and was the first plant in Region II to chemically
clean a safety related system. An inadequate 10 CFR 50.59 safety
evaluation prior to this chemical cleaning resulted in violation b.
below.
Two violations were identified in the Radiological Controls area.
a. Severity Level IV violation fo'r failure to install standby
service water basin chemical addition system as shown on
temporary a1teration. (416/87-10-09)
b. Severity Level IV violation for an inadequate safety evaluation
for chemical cleaning of s tar.dby service water piping.
(416/87-39-01)
2. Conclusion
Category: 1
3. Recommendations
A high level of performance was achieved in this area. The NRC
staff resources applied to the routine inspection program should
be reduced.
C. Maintenance
1. Analysis
During this assessment period, inspections were conducted by the
resident and regional inspection staff. Significant maintenance
activities were performed during the two major refueling outages
during this SALP -period. Inspections were performed on the
-Maintenance program, its implementation and of equipment availability
and accessibility by a PRA-based inspection team.
Licensee management has been responsive to NRC concerns. For
example, inspectors identified the use of excessive amounts of what
appeared to be silicone grease on airlock door seals to enhance
inflatable seal performance and noted that the airlock door seal
testing was not being conducted in the as-found condition. Based on
the inspectors comments, licensee management initiated procedural
changes to test the inflatable seals in the as-found condition and
the use of excessive lubricant on the seals was minimized such that
there is no visible evidence of lubricant.
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The licensee's approach to the resolution of technical issues was
good and management's involvement was evident. Fur ev. ample, during
the second refueling outage the licensee fcund indications of cracks
in the exhaust manifold inlet housing for the turbo-charger on the
Division 1 diesel generator. In two followup telecons the licensee
informed the NRC of their findings and planneJ actions. A final
report was thorough and responsive to the NRC on this issue.
At times maintenance activities were not always well controlled. For
example a valve in the control rod drive hydraulic system was found
with the bonnet removed and with no protection from foreign material
intrusion. A previous event at Grand Gulf documented in IE Informa-
tion Notice 86-89 oi an uncontrolled control rod withdrawal event
where the licensee had concluded that particulate accumulation on a
solenoid operated directional control valve caused an incomplete
closure of that valve allowing drive water pressure to leak past the
valve and force the uncontrolled control rod withdrawal.
The licensee has initiated a Maintenance Improvement Program. In
1986 and 1987 there were multiple assessments by Middle South
Utilities, INPO and other industry groups. Various improvement
initiatives were recommended. One major initiative incorporated to
date includes a new Planning and Scheduling department with a
Planning & Scheduling Superintendent having a Planning Group, a
Scheduling Group and a Maintenance Engineering Group reporting to
him. These tasks were formerly spread out among the Electrical,
Mechanical, and Instrumentation and Control Superintandents.
Another initiative the licensee has taken was to purchase equipment
to perform Motor Operated Valves (MOV) testing in order to determine
the desired torque switch setting for safety related MOVs. The
result of the testing in response to IE Bulletin 85-03 was completed
in January 1988.
The objectives of the maintenance programs inspections were to
determine whether the GGNS maintenance program is being implemented
in accordance with Regulatory requirements, and to determine the
ability of the licensee to conduct an effective maintenance program
on important plant equipment. There were no adverse findings
identified.
The PRA-Based team inspection in October 1987 examined equipment
availability and accessibility. Management involvement and ' nowledge
- of maintenance activities was indicated by clear, concise ;rocedures
l provided for maintaining safety-related and balance of plant
components. The licensee's procedures were generally wr 11 prepa ed
especially with regard to technical content and humin factors l
considerations. Minor discrepancies were noted in a fsw procedures
(e.g. , partly illegible figures). Good records were available to
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determine equipment- status. An - automated + racking system for
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maintenance is being developed. The procedures for design control
were judged to be above average. The program calls for updating
control . room drawings within 14 days and other drawings within 90
days.after a plant modification has been completed. This program has
made. significant improvements and appears to be working very well.
Numerous _ questions were raised regarding electrical 6esign and
maintenance practice. These questions were promptly responded to and
generally were accepted as welcomed ideas-to improve plant safety and
maintenance.
Two violations were identified. This reflects a significant
improvement over the previous SALP in which seven violations were
Identified.
.a. Severity Level IV Violation for failure to follow procedures for
procurement of components. (416/88-07-03)
b. _ Severity Level V Violation for failure to document the deficient
reassembly of a relief valve. (416/87-10-04)
2. Conclusion
Category: 2 Improving
3. Recommendations
The NRC staff resources applied to the routine inspection
program should be maintained.
D. Surveillance
1. Analysis
During this assessment period, inspections were performed by the
resident and regional inspection staffs. Inspections performed were
associated with the PRA-based team inspection, core power testing,
routine surveillance observation, safety valve testing, and event
followup.
Meetings were held with SERI management during April and June 1987
to discuss NRC concerns in the surveillance area. The licensee has
,
been responsive to NRC concerns and has tcken actions that reduced
the number of missed surveillances. During tne previous SALP period
12 LERs were in the area of missed surveillances out in the current
SALP period only one LER was in the area of missed surveillances.
The total number of LERs in the surveillance area for this SALP
period was 16 as opposed to 26 during the previous SALP period.
Although this shows improvement, there is still need for management
attention.
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Surveillance procedures were not always clear in defining acceptance
criteria. In' many cases the technician in the. field 'was lef t with -
the decision . of what tolerances were acceptable during certain
calibration _ or functional tests. For example, it was noted that
iduring a calibration . step, the procedurc required an LPRM gain
control adjustment to achieve 8.000 DC volts on the digital volt
meter and no tolerance was specified. Licensee personnel involved in -
the_ calibration accepted from 7.990 to 8.010 DC volts which was not
allowed by the procedure. A diesel generator functional test
required that the fuel oil transfer pump should automatically start
when the day tank -level reaches 26 inches and should automatically
stop when the day tank level reaches 39 inches but no tolerance was
specified. The fuel oil transfer pump started and stopped within
approximately one inch of the noted values and was accepted.
An example of an inadequate event followup is the March 2, 1988 trip
of _ the Division 2 Diesel Generator during a surveillance and the
Special Report that was suomitted. Ther_e were several erroneous
statements in the Special Report that were corrected during a telecon
on March 31, 1988, between NRC Region II and licensee management
regarding this event. A second similar diesel trip had occurred on
March 30, 1988, and the Special Report was revised to correct the
reason for the diesel trips and other erroneous statements. The
licensee has subsequently experienced similar diesel generator trips
that may be related to the events discussed in the Special Report.
The licensee and the diesel manufacturer are presently investigating
the. trips.
Surveillance programs for electrical switchyard equipment, emergency
diesel generators and standby service water system were inspected
during the PRA-Based- inspection conducted in October 1987.
Procedures were examined, some tests were witnessed and past test
records were reviewed. Generally, the procedures were well written,
clear and concise. Records are complete and well maintained and the
procedures appear to be followed.
One deviation _was identified which involved failure to complete a
functional surveillance test on protective relay systems. The FSAR
committed to a functional test of the relays and control equipment on
a two year or less frequency. This test was last done in June 1983,
almost 4-1/2 years late. The licensee researched this finding and
took prompt corrective action. The problem was attributed to
interface problems involving two separate organizations. All other
safety-related and balance of plant surveillance activities inspected
were found satisfactory.
Safety relief va!ve (SRV) set point testing and safety relief valve
logic system function testing was also inspected. Several safety relief
valves experienced set point drift that exceeded Technical
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GGNS guidelines requiring further disassembly and inspection. The
greatest deviation was 6.1%. There was no evidence of the cause of
drift. Other valves required setpoint readjustment. NRC has issued
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several Information Notices concerning SRV failure to lift. Review
of _ licensee procedures indicate . technically sound and thorough
responses to these information notices.
Reactor core stability testing was conducted in a well organized
manner. Personnel present performing the test were knowledgeable
about the testing to be performed, Management took an active part in
insuring the testing would be performed as scheduled and that the
< plant would.not be maneuvered into operational regions not called out
in the' test or into operational regions where core thermal limits
would be approached. The test was being performed voluntarily to
take data in regions of operation estimated to be approaching
instability. .The test verified actual stability was higher than
estimated.
The licensee's improved program for core power distribution
monitoring, and analysis and control of thermal limits reflects a
considerable investment in equipment and human resources. The major
equipment investment is in two . computers, 'each redundant to the
other, in order to perform rapid online analysis not possible in the
originally -installed system, which now functions primarily as a data
link to the new computers. In addition, the licensee has installed
computer terminals at the residences of three specially and
intensively trained engineers, one of whom is always on call. This
effort has provided operations around-the-clock, on demand
assistance. This assistance includes prediction of control rod -
movement effects on thermal limits, fuel preconditioning, and fuel
utilization; all derived from the capability to perform full-core,
three-dimensional calculations in a matter of minutes.
Five violations and one deviation were identified. Although the
violations are diverse and do not indicate a programmatic deficiency,
they do reflect a lack of attention to detail.
a. Severity Level IV violation for failure to provide and implement
an adequate procedure for the surveillance testing of the
Standby Liquid Control System. (416/87-14-03)
b. Severity Level IV violation for failure tu document and evaluate
test discrepancies during Standby Liquid Control System Testing.
(416/87-26-03)
c. Severity Level IV violation for failure to document nitrogen
hookup to offgas system charcoal beds and the inadvertent
actuation of an ECCS. (416/88-03-01)
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d. Severity Level V violabon for failure 4 determine normal
indicated delta pre.-sure and set LPCS and LPCI header delta
. pressure instrumentation as required by T! 4.5.1.c.2(b).
(416/87-40-01)
e. Severity Level V violation for failure to follow procedures for
the'IRM. Range 6 to Range 7 correlation ter . (416/86-39-07)-
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f.. . Deviation' for failure to perform functional check on 500 KV
relay system as committed in the FShR. (416/87-27-01)
1
2 .- Conclusion-
Category: 2
4
. 3. Recommendations
The-Board noted that' inadequate procedures resulted in increased
ESF: actuations. Additionally, acceptance criteria was
inadequate .in that it did not clearly specify tolerance bands.
'The NRC - staf f resources ~ applied to the routine inspection
program should be maintained.
E. . Fire Protection
1. Analysis
During this assessment period, inspections were conducted by the
. gional and' resident inspection staff to review the licensee's
implementation of the fire protection program and followup on
previously ' identified enforcement matters.
The . licensee has issued revisions to procedures for the
administrative control of fire hazards within the plant, surveillance
and maintenance of the fire protection systems and equipment, and
organization and training of the plant fire brigade. These
procedures were reviewed during the staff inspections and found to
meet NRC requirements and guidelines.
The staff inspections also reviewed the licensee's implementation of
the fire preventive administrative controls. General Nusekeeping
arid control of combustible and flammable materials in safety-related
plant areas were found to be very good. The fire protection
extinguishing systems, fire detection systems and fire barrier
assemblies protecting plant systems required for safe shutdown were
found to be functional. In addition, the surveillance inspections,
tests and maintenance instructions for the plant fire protection
systems were found to be very good and they met the criteria of tne
plant technical specifications.
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The~ annual fire protection / prevention audit and 24 month QA fire
- protection program audit by offsite organizations' and the triennial
audit by an outside fire protection l organization required by .the
technical specifications were. reviewed. These audits were conducted
within the specified frequency. .The licensee had implemented the
corrective actions on discrepancies identified by these audits.
, Management involvement and cont'rol in assuring quality in the fire
=
protection program is evident due to' the well developed, issued and
. implemented fire protection administrative procedures. The
. licensee's approach to resolution of technical fire protection issues-
indicates an understanding of issues, and is sound and timely. The
responsiveness to NRC initiatives are timely and thorough. Fire
protection related violations are rare. When violations do occur,
effective corrective action is promptly taken. Fire protection
related events and discrepancies identified by the licensee are
properly analyzed and promptly reported and effective corrective
actions are taken.
The organization and staffing of the plant fire brigade is adequate
to meet NRC guidelines. Fire protection personnel are identified and
authorities' and responsibilities are clearly defined. Personnel
. appear well qualified for their assigned duties.
Management attention to the fire protection area is evident from the
large reduction in the number cf outstanding limiting conditions for
= operation in-this area during this SALP period.
No violations were identified in this area.
2. Conclusion
Category: 1
3. Recommendations
A high ' level of performance was achieved in this area. The NRC
staff resources applied to the routine inspection program should
be reduced.
1. Analysis
During the assessment period, inspections were performed by resident
and regional inspection staffs. These included observation of the
annual emergency prep'a redness exercises in December 1986 and November
1987.
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The ~ two emergency exercises during this assessment period reflected
the increased management attention being directed to improving the -
emergency preparedness program. . Weaknesses noted in the report of
the previous assessment period were corrected. There were no
exercise weaknesses observed during the exercises and only five minor
observations that warranted attention / improvement by . the licensee.
The exercise observations indicated that the primary responsibilities
for emergency response by site personnel. and supporting corporate
staff had been.specifically established and could be implemented in a
timely and effective manner. The emergency organization used its
emergency classification and action level scheme to promptly and
properly classify the emergency situations. The required
notifications were made promptly and protective action
recommendations were made correctly in accordance with procedures.
The emergency personnel demonstrated effective teamwork in accessing
and mitigating the postulated accident scenarios.
The routine inspections disclosed that the licensee had an adequate.
' emergency preparedness program for emergency detection and
classification, protective action decision-making, shift staffing and
augmentation, notifications and communications, changes to the
emergency preparedness program, and licensee audits. The knowledge
and performance of duties were found adequate with the exception of a
violation for failure to provide training for two emergency response
personnel in accordance with the emergency plan procedure. It was
also'noted that training records needed te be maintained better.
In order to place greater emphasis on Emergency Preparedness, the
licensee created the position of Manager of Emergency Preparedness
who answers directly to the Vice President, Nuclear Operations.
The licensee has been responsive to NRC concerns. For example, in the
inspection report citing Violation b. below, the inspectors also
-noted concerns regarding the licensee's overall alert notification
system. In response, the licensee developed an extensive long term
and short term corrective action program involving procedural,
- training and equipment changes. Within thirty days, the existing
Claiborne County transmitter and antenna were replaced to increase
system reliability. The licensee is procuring a computerized siren
activation and monitoring system which will provide the local
government agencies the capability to monitor the status of each
siren from the control station. The new system will eliminate the
need for manual data retrieval as presently required. The licensee
now expects to have the new system installed by July 1988.
i As part of the transition from MP&L to SERI, the licensee presented
l an Emergency Preparedness Transition Plan to the NRC. The transition
has been accomplished smoothly and in a professional manner with no
impact on emergency preparedness capability. To ensure the NRC was
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kept aware of the SERI change over status, the licensee held
L quarterly update meetings.
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Two violations' were identified.
a. Severity Level IV violation for failure to provide training for
emergency response personnel in accordance with emergency plan
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procedure-(416/87-16-01).
.b . ' Severity Level IV violation for failure to notify -the NRC of
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alert notification failure. (416/87-18-05)
'2. Conclusion
Category: 2' Improving
3. Recommendations
The Board noted that management attention and initiative is high
with day to day involvement resulting in significant effort
towards correcting previous -issues. The NRC staff resources
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applied to the routine inspection program should be maintained.
G. Security
1. Analysis
During this assessment period, inspections were performed by the
resident and regional inspection staffs. There is clearly
demonstrated a continued strong management support of the security
. program at both corporate and . site levels. The site security force
continues to implement and enforce regulatory requirements in an
effective and aggressive manner. The contract security force
productivity is assured - by application of credible supervisory
expertise and professional managerial oversight by . proprietary
managers as evidenced by . the effectiveness of the security force
noted during inspections.
The licensee continued to demonstrate awareness of changes and new
requirements prescribed by . regulatory directives and initiated
necessary changes to -plans and procedures in a timely manner.
Changes to physical security, safeguards contingency and security
-training and qualification plans are detailed and clearly define
commitments and implementing requirements. The manner and timeliness
in which the licensee implemented the provision of 10 CFR 73.57 with
regard to submissions of fingerprint cards for all personnel
requiring protected area access to safeguards information was
noteworthy. The licensee has also been responsive to NRC concerns.
For example, in response to NRC comments regarding the lack of
clarity of ~ the image on x-ray equipment, the licensee replaced the
existing x-ray machines with improved model X-ray machines with
greater resolution.
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~As previously reported, the licensee.has not finalized their decision
.on upgrading the interim protected area barrier between the-
operational Unit ~1 and Unit 2. Their decision' has been delayed
.pending the final resolution of Unit 2. However, in the interim the
' licensee: has enhanced the security of the interim barrier beyond
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-commitments of the Physical Security - Plan by installing intrusion
detection equipment on the roof of the control and turbine buildings- !
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and increasing the frequency of security patrols.
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The ~ licensee continues to log and report as appropriate, physical
security events in accordance with 10 CFR 73.71 accurately and in a
timely manner except as noted below. During the first quarter of
FY-88 the licensee conservatively reported under the revised criteria
of 10 CFR 73.71, a total of 312 physical security events. Unit 1 was
undergoing a refueling _ outage during this period, and _ many of the
events were intrusion alarms attributed to outage personnel failing
l- to adhere to access control procedures. During the second quarter of
FY-88 the event rate was reduced by 65% to a total of 109 events
which.is partly attributed to additional guidance provided by the NRC
l
on.reportability under 10 CFR 73.71.
! A special inspection during this assessment period confirmed the
i occurrence of two licensee identified violations relating to a delay
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in response to an intrusion alarm from a vital area door and
exceeding the one hour reportability requirement. The licensee's
corrective- actions were in accordance with criteria for categoriza-
tion as licensee identified violations and no violations were cited.
No violations were identified in the security area.
2. Conclusion
Category: 1
3. Board Recommendations
A high level of performance was achieved in this area. The NRC
staff resources applied to the routine inspection program should
be reduced.
H. Outages
1. Analysis
i
During this assessment period, inspections were performed by the
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resident and regional inspection staffs. Two major refueling outages
occurred during this SALP period.
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The . first refueling outage started on September 5, 1986, and was
- scheduled to end on November 22, 1986. Reactor restart was initiated
on November 30,1986 but while attempting to roll the turbine for the
-turbine overspeed trip . test, damage to the turbine / generator rotor
and number 10 bearing was discovered. A wrench socket had
inadvertently been left in the bearing during outage work. -The plant
resumed corenercial operation on ' January 9,- 1987. The major tasks of
the first re 'ueling outage were the rework of the cooling tower for
inc eased efficiency, the replacement of 264 fuel bundles in the
reactor core, the modification of the A standby service water system
for increased capacity, the disassembly and inspection of the
Division 2 diesel generator and the license conditions requiring
modifications. The plant General Manager held meetings on January 8
& 9, 1987-to discuss GGNS performance during 1986 with all employees
and to. discuss lessons learned from the first refueling outage.
The second refueling outage began on November 7, 1987, with a
scheduled .startup date of January 5,1988. The plant went back on
line January 6, 1988. Major work items during the second refueling
outage consisted of disassembly / inspection of one low pressure
turbine with rotor disc UT inspection, replacement of 288 fuel
bundles, reactor vessel internals inservice inspection, disassembly
and inspection of the Division I diesel generator, chemical cleaning
of the standby service water basin and flow balance, chemical
cleaning of the circulating water system, installation of an on-line
condenser tube - cleaning system, control room redesign work and
standby liquid control system redesign work.
The refueling floor activities were conducted in a controlled manner.
The actual fuel handling was accomplished by GE personnel with a SERI
Senio. Reactor Operator in charge of the refuel floor. A Senior
Reactor Operator remained on the refueling bridge during actual core
alterations conducted from the refueling bridge. One event occurred
where a polar crane operator attempted to move a reactor vessel head
stud tensioner over the corner of the upper containment pool fue.1
storage racks. Only new fuel was stored in this area but Technical
Specifications prohibit loads over 1140 pounds being moved over this
area. The Senior Reactor Operator on the refuel floor stopped the
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crane but not before it reached the corner of the fuel storage racks.
The licensee required GE to formalize their control over refueling
floor activities and added a SERI manager on the refuel floor to
oversee GE's performance until adequate performance was demonstrated.
Management was heavily involved in the planning and scheduling of the
refueling outages. Management attention was evident due to the
assignment of key personnel to major work areas. An experienced
Senior Reactor 09erator was assigned to the Outage Scheduling group
in July 1987 to help prepare for the November 1987 outage and the
Technical Assistant to the Manager, Plant 7perations, who holds a
Senior Reactor Operator license, was assigned as the Outage Director.
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One event that displayed management involvement concerned a stuck
fuel bundle. On November 19, 1987, during a core fuel shuffle a
peripheral fuel bundle could not - be removed within the technical
specification limit of-1200 pounds on the refueling platform bridge
main hoist. The licensee with GE's assistance evaluated the problem
and with discretionary enforcement relief from the NRC, managed to
remove the stuck fuel bundle without any damage. The~ licensee has
incorporated procedural improvements to prevent the recurrence of
this event.
Plant management was actively involved in plant activities on a daily
basis and was involved ir ensuring that operational decisions were
made at the appropriate level. Plant management has been very
responsive to NRC concerns and their actions have reflected a careful
conservative approach to safety and operational issues. Management's i
conservative approach has been emphasized during outage briefings by {
asking everyone to contribute to meeting the work schedule but not at
the expense of safety or quality. Licensee Management took special
- precautions to minimize potential problems during the outage. For
example, to minimize the potential for draining the reactor vessel,
controls were established to require both the Refueling Floor
Coordinator and the Shift Superintendent to approve manipulation of
any valve which could drain the vessel while the vessel head was
detensioned. A status board was aoded in the control room indicating
the operable ECCS system, the shutdown cooling mode being utilized
and the status of all systems which could cause inadvertent vessel
draining. The duration that two RHR shutdown cooling loops were
inoperable was minimized. Some contingencies added for evacuation
and closure of containment were a temporary containment hatch which
could be set in place in less than five minutes to minimize air flow
between containment and the auxiliary building and the containment
air locks were maintained in a condition where a' least one door
could be manually closed.
Inservice Inspection (ISI) activities were examined in three
inspections conducted during the assessment period. The activities
were found to be closely and effectively monitored and controlled by
licensee manacement. The procedures, work and records were judged
sound and conservative in addressing technical issues and in
implementing responses to NRC initiatives. ISI related issues, such
as those described in NRC Generic Letter 84-11, were found to be
, promptly and satisfactorily resolved. Procedures and records were
complete, technically adequate and well-maintained. Licensee control
of contractors performing ISI was exemplary.
Two violations were identified. During the first refueling outage
one violation was issued with six examples of failure to follow
procedures or failure to have adequate procedures. Additionally,
there were other events that occurred that did not result in a
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violation bu't indicated inadequate control of work activities in the
. plant. The residents discussed their concerns with plant management
and work activities were reviewed by the licensee and better work
controls were established. For example, the Shift Superintendents
duty -station was moved into the. control room and additional reviews
of work' packages was initiated. The rate of incident occurrences
decreased during the latter portion of the first refueling outage.
' During thel second refueling outage, one violation was issued with
four examples of failure to follow procedures ~ or failure to have
adequate procedures. Although the number of events were less than
during the first refueling outage, there still appeared to be an
excessive number and indicates a need for further work control
improvements. Primarily, the events resulted in -the inadvertent
actuation of engineered safety features (ESF) and the reactor
protection system indicating a loss of control of plant status. The
licensee recognizes that violation b. is a repeat of the violation a.
and that additional management controls are still required.
Corrective actions were initiated during the latter part of the
second refueling outage to prevent recurrence of the noted events.
Also, the licensee is conducting a post outage cr'tique to identify
any further programmatic control changes that may be required. Plant
procedure improvement regarding major power outages is scheduled to
be available by the start of the third refueling outage.
a. Severity Level IV Violation with six examples. Four examples of
inadequate procedures resulting in ESF actuations and faulty
equipment installation, one personnel error resulting in an ESF
actuation and one failure to follow procedure resulting in
possible equipment damage. (416/86-37-01)
b. Severity Level IV Violation with four examples. Three examples
of inadequate procedures resulting in an ESF actuation, a
reactor protection system actuation and capping a post accident
pressure sensing line and one example of failure to follow
procedure resulting in an ESF actuation. (416/87-35-01)
2. "onclusion
Category: 1
3. Recommendations
A high level of performance was achieved in this area. The NRC
staff resources applied to the routine inspection program should
be reduced.
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I. Quality Programs and Administrative Controls Affecting Quality
1. Analysis
, During- the assessment period, inspections were performed by the
resident and regional inspection staff.
For the purposes of this assessment, this area is an evaluation of
the ability of the licensee to identify and correct their own
problems. 'It encompasses all plant activities, all plant personnel,
as well as those corporate functions and personnel that provide
services to the plant. The plant and corporate QA staff have
responsibility. for verifying quality. The rating in this area
specifically denotes results for various groups in achieving quality
as-well as the QA staff in verifying that quality.
A QA effectiveness review was performed in March 1988, to assess the
effectiveness of licensee actions to correct weaknesses identified in
selected functional areas during the. September 1986 QA effectiveness
review. Both of these reviews utilized licensee imposed performance
indicators as a basis for assessment.
During the March review, several previously identified weaknesses had
improved. The ' licensee had reduced the number of reactor trips
resulting from- operator errors and/or procedural -inadequacies.
Improvements were made in configuration control, design control and
in the reduction in the number of change notices to design
modifications.
Effective July 1987 the Director, Quality Assurance became the
Director, Quality Programs; the Manager, Nuclear Site QA became the
Maaager, Quality Services; the Manager. Audits QA became the Manager,
Quality Systems; and the position of Manager, Programs QA was
deleted.
To have an effective corrective action program all significant
personnel errors, equipment failures, etc. must be documented for
review and analysis so appropriate corrective actions can be taken to
preclude repetition. Sometimes the licensee was hesitant to document
such events. The residents identified the licensee's failure to
initiate nonconformance reports on discrepancies nott d during Standby
Liquid Control (SLC) system operability testing and SLC system relief
valve functional testing. Violation b. in the Surveillance section
of this report discusses the licensee's failure to document these
discrepancies.
The licensee's program has failed to identify some significant
deficiencies. An example is the event discussed in the Engineering
Section concerning the resident inspector's identification of a
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missing bolt sin a- control rod drive Hydraulic Control- Unit (4CU)
mounting _ structure. .In addition to _ the inadequate Engineering
evaluation, it is significant to note that the work in question had
'been performed by Reactor Controls _ Incorporated (RCI). The licensee
had previously submitted several Potentially Reportable Deficiencies
(PRDs) during the construction phase regarding deficiencies _with work
performed by RCI. The failure to identify the .significant-construction
deficiency even after-the noted concerns indicates a failure in the
-licensee's Quality programs.
One initiative' by the licensee to enhance the audit process was to
H combine the efforts of Quality Programs (QPs) and Radiological and
Environmental Services (R&ES). The licensee observed that QP audits
and R&ES appraisals of similar scope would be performed at approxi-
mately the same time frame placing an unnecessary burden on plant
.
_ personnel. To perform more ef fective audits, the QP audit teams now
utilize the R&ES technical personnel as' technical specialists when
possible for audit functions.
'
The -licensee has shown the ability to correct problems, once
identified, as evidenced by initiating a scram reduction program and
the near miss program, improving f ;el handling procedures, improving
the numbers of missed surveillances and personnel errors leading to
LERs, improving the alert notification system, and . improving the
design . review program. Many of these improved programs were the
result of problems identified by the NRC inspection program.
The licensee was not effective in identifying problems as evidenced-
by poor ; tolerance acceptance criteria in some calibration _ and
. functional tests, functional testing of relays and control equipment
'on a two year frequency, repeat examples of failure .to follow
procedures or inadequate procedure dur.ing refueling activities,
documenting personnel errors and equipment failures so that adequate
corrective action could be taken, problems with HPCS, LPCS, LPCI
header delta pressure, and multiple examples of inaccurate P& ids.
-
No violations were identified.
2. Conclusion
'
Category: 2
3. Recommendations
The NRC staff resources applied to the routine inspection
program should be maintained.
__ . _ - _ _ _ _ _ _ _ _ - - __
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J. Licensing Activities
1. ' Analysis
The licensee's management has been consistently involved in the
- planning and assignment of priorities - for licensing activities.
During this rating period, the last half of the first refueling
outage (RF01) was completed (January 6, 1987) and the second refuel-
ing outage (RF02) was completed. Five months prior to RF02, which
began November 6, 1987, the Vice President - Nuclear Operations, Vice
President - Nuclear Engineering and Support, Director -
Nuclear
Licensing and ati propriate licensee managers and supervisors met with
the NRC Director of Project Directorate II-2, NRC Senior Resident
Inspector, and the NRC Project Manager to brief the staff on RF02
activities and schedule milestones and associated licensing activi-
ties needed to support the outage. An outage goal of eight weeks was
set and the actual outage was eight weeks and two days, which demon-
strates good planning and . implementation of the outage modification
and surveillance activities. Decision' making regarding licensing
activities was adequate and had adequate management involvement in
the decisions reached. Reviews were generally timely, thorough and
technically sound. Most of the submittals of licensing actions
needed to support the outage schedule were timely. For example,
requests to defer TDI diesel generator Division II baseline
inspection recommended by the TDI Diesel Generator Owners Group
(submitted June 30, 1987) and installation of neutron monitors to
meet Regulatory Guide 1.97 recommendations (submitted July 1,1987)
were reviewed and approved in October 1987 without the need for
supplemental information. Another request for relief from a commit-
ment to install containment 4 solation valves was submitted early and
amply supported to allow approval in September 1987, before the
outage started. Similarly, requests for changes to Technical
Specifications regarding snubber surveillance and core alterations
were submitted in a timely manner with adequate technical bases. The
fuel reload was an Exxon fuel reload and used the same analysis '
methods as those approved for reload No. 1 and, therefore, the
October 9,1987 submittal could be approved in a timely manner on
December 15, 1987.
The approach to resolution of technical issues from a safety stand-
point generally demonstrates an understanding of the issues. Out of
33 licansing actions during this SALP period, 50% of the submittals
were timely, demonstrated a clear understanding of issues and were
technically sound and thorough. Another 40% of the submittals were
generally sound and thorough and usually demonstrated a good under-
standing of the issues. However, in 10% of the licensing actions,
the submittals were lacking an understanding of the issues and
thoroughness and resolutions were delayed. Three following examples
illustrate delays due to inadequate submittals.
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.On July 6, 1987, the licensee requested exceptions to Technical
-
Specification 3.0.4 to allow operational mode changes during the
outage without having ECC systems and the RHR system nperational.
The application did-not have adequate technical bases to support its
conclusion that an unspecified alternate decay heat removal means
could be used throughout the outage instead of the specified residual
heat removal system. The licensee was advised soon af ter submittal
that the submittal was inadequate, but it was not until October 8
that a meeting was held in which technical agreement was reached.
The revised application was submitted October 23 and additional
information . was provided November 19. The amendment was issued
December 4, for a TS change needed December 9 when both RHR trains
were scheduled to be removed from service.
A second example of inadequate bases for initial submittal and
delayed resolution of a technical issue is the request to change
Technical _ Specifications for modifications to the standby liquid
. control system to meet 10 CFR 50.62 requirements. The initial
submittal August 13 was technically inadequate because of inadequate
margin between operating pressure and system design pressure and the
proposed change of ASME Code Class 1 piping inside the drywell to
ASME Code Class 2 piping. On August 21 and -September 1, the staff
requested additional information regarding these matters, but it was
not until October 23 that the licensee responded partially and
November 25 when satisfactory piping design modifications were
pioposed. The amendment was needed for startup prior to the
expiration of_ the 30 day comment period and so an exigent Technical
Specification change was issued.
The third example of delayed resolution of a technical issue is the
request to change the Technical Specifications regarding the reactor
water cleanup (RWCU) system. On July 29, 1987, the licensee
discovered that two containment iso * 1 tion valves or, the RWCU pur
suction line used in series shared ne same divisional power supply.
.The licensee's design review of the RWCU also disclosed that piping
components out to the outboard drywell isolation valve were ASME Code
Class 2 and not ASME Code Class 1 as required by 10 CFR 50.55a for
components of the reactor coolant pressure boundary. These errors
and potential corrective measures were discussed with the staff on
September 15. A proposal to exchange power supplied to the two
isolation valves was submitted October 28, 1987, but no proposal was
made regarding the Code classification. The staff returned the
application on November 10 and a revised submittal was made
November 25 simultaneously with a request for exemption from the
requirements of 10 CFR 50.55a regarding ASME Code requirements for
the reactor coolant pressure boundary. The staff granted the
exemption on the basis that an ASME Code Class 1 stress analysis and
ASME Code Class 1 inservice inspections would be performed on the
applicable section of the RWCU piping. However, the late date of an
acceptable resolution resulted in the expiration of the 30 day
. - _ ..
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4
comment period. and amendment issuance on January 4, 1988,'one day
after plant startup began on January 3, 1988. The licensee is
addressing the problem of late resolution of issues needed for
restart from outages and will work with the staff to establish firm
milestones for early resoiation. For example, resolution of neutron
monitors.to meet Regulatory Guide 1.97 is being actively pursued, as
discussed below. Overall, in the resolution of technical issues,
viable and' generally sound and thorough approaches are used and con-
servatism is generally exhibited.
The licensee is generally responsive to NRC initiatives. In many
licensing actions, telephone calls discussir.g the technical issues
resulted in appropriate revisions to the submittals. Most of the
license conditions resulting from the operating license review were '
i
completed by the end of second refueling outage. The few
longstanding regulatory issues, such as containment purge criteria
and hydrogen control final analyses per. 10 CFR 50.44, are not
attributable to the licensee. The licensee has satisfactorily
responded to tne NUREG-0737 issues regarding TMI Action Items and
NUREG-0737, Supplement I regarding emergency response facilities. At
the end of the SALP rating period, only one of these items remains
. unresolved. This i '.e m , a neutron flux monitor to meet the
requirements of Regulatory Guide 1.97, is currently scheduled to be
installed at RF03 and resolutior. of this issue is actively being
pursued by the licensee.
The licensee has also teen responsive -to NRC concerns regarding
procedures for determiaing operability of equipment which is found to
be nonconforming. For example, Material Nonconformance Report (MNCR)
0166-87 was written on May 6,1987, documenting that the electrical
wiring used in the contair, ment and drywell hydrogen analyzer panels
had been replaced with wiring that had not had environmental
qualification testing performed as required by 10 CFR 50.49. A
telecon was held with members of the NRC on May 7, 1987. During this
conversation, the NRC raised the question of permissible time between
the identification of a safety system deficiency and system ,
operability determination. The licensee had expressed the opinion
that, per their procedures, they were allowed seven days for
evaluation. Knowing the wiring in the hydrogen analyzers was
unqualified made the hydrogen analyzers technically inoperable and,
therefore, TS limits for operation with Table 3.3.7.5-1 would have
limited operation to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. Generic Letter 86-15, which addresses
the issue of the lack of environmental qualification states that the
licensee shall make a prompt determination of operability and shall
have a written justification for continued operation. The use of the
licensee's procedural guidance of seven days for evaluation was
misleading. Based on NRC comments, the licensee revised their MNCR
procedure to delete the seven day evaluation reference and now
requires the Duty Manager be involved immediately in evaluations
regarding equipment operability. Ihis is significant when it is
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realized that in the fou'rth quarter of 1987, 75 MNCRs were designated
as requiring further engineering evaluation and, therefore, seven
days were considered available.
The licensee requested discretionary enforcement when it was not
really required due to an inadequate Technical Support Instruction.
On May 13,=1987, the licensee contacted' NRR and NRC Region II for
possible discretionary enforcement. While the NRC was considering
. the request for discretionary enforcement, the licensee found a
letter to the NRC dated June 1984 that nad revised the definition of
trip systems such that the licensee could bypass level trips associ-
ated with a faulty water level reference leg and still meet TS action
statements. .The licensee. had failed to update their Technical
Support Instruction to reflect this change. This is an example of
poor quality assurance on a TS supporting document.
The licensee's staffing for licensing activities was changed when the
Director of Nuclear Licensing and Safety stayed with Mississippi
Power & Light Company after licensing activities were assumed by
System Energy Resources, Inc. The Manager of Nuclear Licensing moved
up to become Director and one of his staf f became the Manager of
Nuclear Licensing. Both of these persons. have long experience in
GGNS nuc:2ar licensing. The day-to-day contacts, coordinating
personnel for telephone calls and meetings have remained good. Some
of the-licensing personnel are onsite and have operational experience
for coordinating and communicating licensing matters to operations
personnel and to the NRC resident inspectors. Positions are
identified and authorities and responsibilities are well defined.
Coordination between licensing personnel onsite with those in the
corporate . of fice is usually good. Staffing has been ample during
this rating period.
The' licensee's submittals of no significant hazards considerations
for licensing amendments vary widely in acceptability. Some are
excellent; for example, the June 3,1987 submittal on core altera-
tions and the July 1,1987 submittal on the relief from the require-
ment for flow measurement in the standby liquid control system.
Deficiencies include a lack of a clear description of the effect of
the change on accident probabilities and consequences. Additional
training in the area of accident analyses should be considered for
the evaluators of license amendment applications.
No violations were identified.
2. Conclusion
Category: 2
3. Recommendations
None
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K. Training
- 1. Analysis
During the assessment . period, inspections were performed by the
(7 resident and regional staffs. Special team inspections involving
! ..
training;were conducted by the: Probabilistic Risk Assessment and
Emergency Operating Procedures inspections.
Licensing examinations were given to 8 Reactor Operator (RO) and 2-
'
,
Senior Reactor Operator (SRO)- candidates in May 1987. Examination
results yielded .a pass rate of 88% (7 of 8) for R0 candidates and a
50% pass rate'for SRD candidates. Examinations were administered in
-April 1988 to three SR0 candidates as well as one RO candidate and
one SR0 candidate who had failed the previous examinations. Three of
-the four SR0s and the R0 passed. The overall pass rate, of 80% is
above the industry average.
Several -weaknesses identified during the May 1987 operating
examinations related to operators improperly paralleling the diesel
generators to the electrical busses.
An evaluation of the ~ requalification program was conducted by
Region II in December 1986. The overall program was rated as
marginally satisfactory. On May 27, 1987, representatives of System
Energy Resources Inc. (SERI) met with NRC Region II personnel to
discuss' improvements to be made in the requalification program as a
result of an internal.. examination. The NRC staff acknowledged the
changes made to the requalification program and ' agreed that those
changes would enhance the program. A similar meeting was. held on
March 2, 1988, in 'which SERI representa'.ives outlined further
improvements which had been incorporated ir;to 'their requalification
program since the meeting with Region-II on-May 27, 1987.
In order to. place a higher level of direct management attention on
training activities at the plant site, beginning in April 1987, the
Training Superintendent started reporting directly to the -Site
Director. The Training Superintendent previously reported to the
Manager, Plant Support.
, Management attention in the area of operator training was eviJett.
There was a special inspection conducted by t;ie NRC in the area of
Emergency Operating Procedures (EOPs). Although there were problems
identified in the E0P program area, operator performance was very
good during the simulator scenarios which were conducted to evaluate
the E0Ps. Also, a special PRA-Based inspection team noted that the
operators performance during the simulator assessments was above
average. The comments reflected the licensees high standard for
,
operator training.
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The licensee instituted a training program to instruct its personnel
4
- in the preparation of 10 CFR 50.59 safety evaluations, based on the
NUMARC draft guidelines which are currently being reviewed by the NRC
staff. Although some retraining may be necessary when agreement on
appropriate guidelines is reached between NRC and NUMARC, many of the
procedural aspects of the training will remain valid and should
improve the' safety evaluations. Evaluators of design and procedure
changes are tested and qualified by supervisors who have experience
in performing these evaluations. The training and qualification
program contributes to an adequate understanding of work and fair
adherence to procedure.
One of the areas inspected during the PRA-Based inspection in October
1987 was operator awareness and training on PRA findings. This was
done by interviewing a number of operators and through use of the
simulator. Two severe accident scenarios were selected for
demonstration on the plant simulator, using an operations crew to
mitigate and recover from the event.
It was found that the operators had not been specifically trained for
the station blackout scenario selected. Their performance, on the
simulator was good, but not as good as for the ATWS event, which was
the second event selected. The training program has not yet embodied
,
blackout recovery, or actions to take to limit the event.
The operators appeared to be well trained on the emergency procedures
as they currently exist. Management involvement and commitment to
training was indicated by the planned modification to the simulator
to match the control room. Modification to the control room was
indicated through a human engineering study and these same changes
were installed at the simulator. The quality of the training program
was indicated by the excellent actions during the simulation of an
ATWS. Operators followed procedures and demonstrated their previous
training on this event.
The licensee attributes the decrease in personnel contaminations to
the improved general employee training progrcms which began to place
stronger emphasis s n practical factor training in late 1986. The
training personnel nrovided the radiation workers with comprehensive
one-on-one practical factor training in mockup of a
contaminated / radiation area. Successful completion of the practical
factor segment of the training was required for course completion.
The training and drills for the fire brigade members met the
frequency specified by the procedures and the NRC guidelines.
No violations were identified in this area.
2. Conclusion
Category: 2
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' 3. Recommendations
The NRC istaff resources applied to the routine inspection
program should be maintained.
L. Engineering
1. Analysis
-During this evaluation period, inspections were performed by the
resident and regional staffs. A' special team inspection was
performed in the area of environmental qualifications (EQ) of
electrical equipment.
Effective July 1987, the Nuclear Plant Engineering Department was
'
reorganized to minimize the number of positions reporting directly to
the Director of Nuclear Plant Engineering. Only the Manager, Nuclear
Design, Manager, Engineering Support and Manager, Operational
Analysis now report directly to the Director of Nuclear Plant
Engineering.
The licensee has been responsive to NRC concerns. Due to tne
numerous design basis documentation / analysis deficiencies that have
been identified and NRC concerns, the licensee initiated a comprehen-
sive design review program. The licensee's design review initiatives
were discussed in an enforcement conference on February 4, 1987.
Although there appears to be a high number of design / documentation
deficiencies, the licensee is commended for initiating the design
review verification program that identified some of the more subtle
deficiencies.
Some engineering evaluations were not conducted to the depth required
to identify tne root cause and implement adequate corrective actions.
The resident inspectors identified a missing bolt in a control rod
drive Hydraulic Control Unit (HCU) mounting structure. Upon
investigation, the licensee then identified numerous additional
installation deficiencies. The first response from Nuclear Plant
Engineering indicated that the as found condition was satisfactory,
but a close review of the analysis by NRC inspectors indicated that
the analysis only covered the configuration after some corrective
actions had been taken. Another example of an inadequate investiga-
tion is the header del ta pressure instrumentation for the high
pressure core spray (HPCS) system, the low pressure core spray (LPCS)
and the low pressure coolant injection (LPCI) systems. See violation
d. in the Surveillance area. In January 1988 during startup from the
second refueling outage the LPCS/LPCI A line break annunciator
alarmed indicating unsatisfactory header delta pressure. Investiga-
tion revealed that the setpoint for the LPCS/LPCI A header delta
pressure had been based upon original design calculations rather than
normal indicated delta pressure as required by Technical
Specifications. Although this same type of problem had previously
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occurred on the HPCS header delta pressure and a GE Service
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-Information Letter and an IE Circular had been ' issued in 1979
addressing this type of problem, the normal indicated header delta
pressure as required by TS had not been determined.
Inadequate drawings -sometimes' contributed to events at GGNS. 'For
example, -there was an event where the concentration of Molybdate in
the SSW basin was decreasing with no apparent cause. The licensee
'found that'a vent line,that acts as a vacuum bre.=ker on the SSW basin
overflow pipe had been inadvertently buried and therefore blocked
causing a siphoning. of water to the storm drain system. The appli-
cable Piping and Ins;rumentation Diagram (P&ID) did not show the vent
line. Even more disturbing is the fact that the vent line was buried .,
and not shown on the P&ID even after a comprehensive de.,ign review
had been conducted on the SSW system due to the many previously
identified design and documentation discrepancies. Another event
where an inaccurate P&ID was a contributor concerns the instrument
air system. P&ID M1067 showed a P53-F496 valve in the Unit 2
instrument air line from the Unit 2 instrument air compressor / dryer
system. The Unit 2 instrument air compressor / dryer system is utilized
as a bhckup to the Unit 1 instrument air compressor / dryer system. An
operator was sent to red tag the Unit 2 P53-F496 valve and mistakenly
red tagged the Unit 1 P53-F496 valve resulting in the loss of
instrument air and almost a scram. The label for valve P53-F496 did
not identify the valve as a Unit 1 valve and the Unit 2 P53-F496
valve shown on the drawing did not exist in the plant. Previous SALP
reports have noted the discrepancies and poor legibility o 5e
P& ids. Although the licensee has initiated an extensive d. . ng
improvement program and significant improvement has been noted, the
events noted above indicate the significance and the need for further
improvement.
During review of IE Bulletin 85-03, "Motor Operated Common Mode
Failures During Plant Transients Dua to Improper Switch Setting," it
was evident that corporate management was involved in site
activities. While completing the bulletin program, the licensee has
encountered relatively few problems. A lot of effort was put forth
to establish a good program from the start which demonstrate a clear
understanding of the issues. All required bulletin responses were
equally timely.
The EQ inspection revealed that the files were generally well
organized, detailed and complete. The EQ program was considered to
be good except in the areas of procurement, train 1ng of material
specialists and dedication process for commercial grade replacement
parts. The weakness in the procurement area resulted in Violation
a. below.
The licensee's actions with regard to NRC initiatives, especially
during the EQ inspection, were timely, correct and thorough. The
resolution of technical issues from a safety standpoint were
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generally sound; however, there were examples identified ifur'ing the
inspection and documented in the report as violatiens and unresolved
items,that indicated a better job could have been done in establish-
ing more complete EQ documentation and better EQ procurement and
maintenance practices. ,
The first four violations were in
~
Six' violations were identified.
the ~ EQ - area ' which did not indicate .a progra;nmatic breakdown.
Management demonstrated an active participation in EQ issues and
placed EQ issues on a high priority.
a. . Severity Level -IV violation for commercial gradc components
installed in EQ equipment (416/87-32-01).
b. Severity Level IV violation of limitorque MOV T-Drains and
grease reliefs (416/87-32-02). <
c. Severity Level IV violation for installation of Raychem heat
shrink tubing in unqualified ccnfigurations (416/97-32-03).
d. Severity Level IV violation on qualifications pacPage for
lubricants (416/87-32-04).
e. Severity Level IV Violation for failure to perform a w.-iaen
safety evaluation. (416/88-07-02)
f. S1 verity Level IV violation for failure to install control rod
drive hydraulic units per design drawings (416/87-10-10).
2. Conclusion
Catenory: 2
3. Recommendations
The NRC staff resources applied +o the routine inspection
program should be maintained.
V. SUPPORTING DATA AND SUMMARIES
A. Licensee Activities
During this assessment period, the licensee completed refueling
outage No. 1, fuel cycle No. 2, refueling outage No. 2 and four
months of fuel cycle No. 3.
This performance assessment is based on the evaluation of the
licensee's performance in supoort of licensing actions for Unit 1.
(Licensing activities for Un' 2 were minimal). The Un't i licensing
._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ __ _ _ _ , _ _
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actions included the licensee requests for license amendments,
responses to generic letters and various submittals of information
for multiplant and NUREG-0737 actions.
'
There were 20 plant specific licensing actions completed during this
SAlp period. Of these, three concerned resolution of outstanding
issues in license. conditions, two concerned deletion of requirements
based on operating experience, two involved training program reviews,
one was relief from a prelicensing-commitment, three were results of
performance or surveillance tests, two related to design analysis of
modifications, three were revisions to the ODCM or PCP, one was
administrative, and three were responses 'to generic letters. The
more significant submittals were design of equipment for ATWS
. mitigation per.10 CFR 50.62 and conformance to Regulatory Guide 1.97
per-NUREG-0737, Supplement 1.
During this SALP period, there were 17 meetings with the licensee.
Six meetings were held to discuss the scope and schedule for
licensing. actions. Five meetings were held to have technical
discussions of specific licensing actions, including containment
purging, reactor core thermal and hydraulic limits, exceptions to
Section 3.0.4 of=the. Technical Specifications, relief from inservice
inspection. requirements for the reactor pressure . vessel and
modifications to the reactor water cleanup system and the standby
liquid control. system. Four trips to the plant were made to observe
core thermal hydraulic tests, to tour the facility, and to be briefed
on operations by plant operations personnel. In two trips to the
plant, the Project Manager participated in inspection activities.
B. Inspection Activities
During the assessment period, routine inspections were performed
by the resident and regional inspection staffs. Special team
inspections were corducted in the areas environmental qualification
, of electrical equipment, probabilistic risk assessment and emergency
"
operating procedures. Two emergency preparedness exercises were
evaluated.
C. Licensing Activities
Schedule Extensions Granted
Two schedule extensions were granted during this SALP period;
completion of the TDI Division II inspection recommended by the TDI
Diesel Generator Owners Group was deferred from the second refueling
to the five year inspection, and the installation of neutron monitors
to meet the requirements of Regulatory Guide 1.97 was deferred from
the second refueling to the third refueling.
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-Relief from the~ requiv ements of Section XI of- the ASME Boiler and
Pressure Vessel Code far inservice inspection of the reactor coolant
Mystem was granted for fivs areas.
'
Exemptions to the rules were granted for (1) use of MSA GMR-1
canisters in high radiation areas, in lieu of oxygen . supplied
breathing masks, and (2) use of ASME Code Class 2 piping in lieu of
ASME Code Class 1 piping in the reactor water cleanup system.
Twenty license amendments were issued. Major amendments included;
addition of TOI diesel generator maintenance and surveillance-
requirements, ' transfer of control of licensed activities from-
Mississippi-_ Power & Light Company to System Energy Resources, Inc. ,
and Technical Specification changes to implement decreased cold fast
starts of diesel generators, exceptions to Section 3.0.4 of Technical
Specifications-(TS) for the second refueling outage and ATWS-related
equipment modifications.
One emergency TS was granted to prevent delay in restart from the
refueling outage. The TS for ATWS related equipment was issued with
less than the 30-day comment period required for a normal amendment,
because the licensee was able to improve its outage schedule by
several days.
~D. Investigations Review
None
E. Enforcement History
'1. Civil Penalties
No escalated enforcement actions were issued during this period.
2. Orders
None-
F. Licensse Conferences
December 15, 1986 Meeting at GGNS by Region II management to
assess the plant status, major problems and
corrective actions and plant tour.
February 4, 1987 Enforcement conference at Region II to
review NRC concerns regarding the Standoy
Service Water system problems. No violation
was issued.
V September 15, 1987 Management meeting at Region II to discuss
two recently identified design deficiencies.
The design deficiencies were in the RWCU
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system where two -redundant isolation valves
shared a . common. power source and where
control building ventilation duct sections
were .not designed to . withstand a design -
basis tornado loads.
December 2, 1987 Management meeting at .GGNS to' brief NRR's
' Director, . Project Directorate II-1, and the
assistant Director for Region II Reactors on
SERI's Operations and status.
February 2, 1988 Management meeting at GGNS to brief the NRC
Region II Regional Administrator and the
Deputy Director, Division of Reactor Safety
on.SERI's operations and status.
March 4, 1988.
.
Management meeting at GGNS to brief the NRC
Region II Dire; tor, Division of Reactor
Projects, and the cognizant Branch Chief on
SERI's operation and status.
G. Discretionary Enforcement
November 23, 1987 Permitted the refueling platform main hoist
cable load to reach 2000 pounds and an
auxiliary hoist to reach 1000 pcunds - to
remove a misaligned stu;k fuel bundle,
' Technical Specification 3.9.6.1 limited
..
loads on the refueling platform main hoist
to 1250 pounds.
-H. Licensee Event Reports (LERs)
The distribution of the events analyzed by cause by the licensee were
as follows:
l
- Cause
l' Component Failure 8
i Design 4
'
Construction, Fabrication, or Installation 2
4
Personnel
- Operating Activity 5
- Maintenance Activity 5
- Test / Calibration 4
- Other 6
Quality Contro; 4
Out of Calibration U
Other _1
TOTAL 39
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I. Ins- tion Activity and Enforcement
,
FUNCT10NAL NO. OF DEVIATIONS AND VIOLATIONS IN EACH'
SEVERITY LEVEL
AREA- Dev V IV III- II' I
Plant Operations 1 1
Radiological Controls 2
Maintenance. 1 1
'
Surveillance 1 2 3-
Fire Protection
Security _
Outages 2
Licensing
Quality Programs and.
Administrative ~ Controls
Affecting Quality
Training
Engineering 6
TOTAL 1 4 17
J. Reictor Trips
June 29, 1987 The unit was operating at 100*4 core themal power
(LER 87-009) when a main turbine trip resulted in a reactor
scram. Ar Agastat relay f ailure resulted in the
closure of the steam jet air ejector main steam ;
isolation valve resulting in the loss of the
steam jet air ejector and loss of main condenser
vacuum giving-the turbine. trip,
August 6. 1987 The unit was operating at 100*4 core thermal
(LER 87-012) power when a turbine control valve fast closure
resulted in a reactor. scram. Moisture
condensation in a switchyard ~ terminal' cabinet ,
caused operation of a lockout relay opening two
switchyard breakers giving a main generator load
rejectiore.
January 10, 1988 The unit was operating at 95"; reactor thermal .
4
(LER 88-002) power when a main turbine trip resulted in a !
reactor scram. The B main ' transformer failed
giving a phase differential load reject and
turbine control valve fast closure.
t
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_- _ _ -
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40
January 20, 1988 The unit was operating at 96% reactor thermal-
(LER 88-006) power when a low reactor. water level gave a
reactor scram. The A circulating water IP
condenser manway leaked spraying water onto the
low hotwell level switches causing a 'short and
false low condenser hotwell level signal and trip
of the condensate pumps.
March 15, 1988 The unit was operating at 100% reactor thermal
power when 29 rods inserted during a Rx sessell
water level surveillance. The surveillance
inserted a half scram and 29. control rods had
lost power to the opposite division scram
solenoid (A Div) due to a loose screw in a
terminal cabinet.
EFFLVENT SUMMARY FOR GRAND GULF
Activity Released (curies) 1985 1986 1982
1. Gaseous Effluents
Fission and Activation Gases 1.51 +28 1.34E+2 2.08E+2 ,
Iodines and Particulates 7.53E-4 4.85E-4 4.28E-3
- ,
2. Liquid Effluents *- 4
'
Fission and-Activation 2.13E-1 3.03E-1 3.66E-1
Products
Tritium 5.17E0 1.47E+1 1.83E+1
Offsite Oose Estimate (mrem)
Maxim;m Whole Body: Liquid 7.02E-2 6.21E-2 1.00E0
Gas 3.11E-i 1.78E0 3.40E-1
Maximum Organ: Liquid 3.92E-1 5.67E-1 1.41E0
Gas 9.03E-2 6.83E-2 ' 36E-1
.
i
2 - 1.51E+2 is equivalent to 1.51 X 10+ I
.
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