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UNIT ED STATES | |||
_ [p 8 42 lo,^ | |||
NUCLEAR REGULATORY COMMISSION | |||
O REGION 11 | |||
'3* . | |||
101 MARIETTA STREET.N.W. | |||
*- ATLANTA. GEORGI A 30323 | |||
\...../ | |||
Report No.: 50-416/86-08 | |||
Licensee: Mississippi Power And Light Company | |||
Jackson, MS 39205- | |||
Docket No.: 50-416 License No.: NPF-29 | |||
Facility Name: Grand Gulf 1 | |||
Inspection Conducted: Ma ch 18 - April 14,1986 | |||
Inspe ors: } 's ** 3 42l | |||
' p R. C. Butcher Senior Resident inspector | |||
. | |||
Date Signed | |||
- | |||
19Al k | |||
,yt,-J. L. Caldwell, Resident Inspector | |||
A,In | |||
Date Signed | |||
Approved by: h <>- - , | |||
2 LkS | |||
H'. C. Ornte, Section Chief Date Si'gned | |||
Division of Reactor Projects | |||
, | |||
SUMMARY | |||
Scope: This routine inspection entailed 155 resident inspector-hours at the site | |||
in the areas of Operational Safety Verification, Maintenance Observation, | |||
, Surveillance Observation, Engineering Safety Feature System Walkdown, Reportable | |||
Occurrences, Operating Reactor Events, Inspector Followup -and Unresolved Items, | |||
and Design Changes and Modifications. | |||
Results: One violation - Failure to change operating procedures affected by a | |||
design change to a safety related system prior to the system being declared | |||
operable. | |||
. | |||
8605060245 860423 6 | |||
PDR ADOCK 0500 | |||
_ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ . __ | |||
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_ . _ .._ _ _ . _ _ _ _ | |||
, | |||
* | |||
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: | |||
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REPORT DETAILS | |||
, | |||
: 1. Licensee Employees Contacted | |||
!- | |||
4 J. E. Cross, Site Director | |||
*C. R. Hutchinson, General Manager | |||
*R. F. Rogers, Technical Assistant | |||
*J. D. Bailey, Compliance Coordinator | |||
4 | |||
*M. J. Wright, Manager, Plant Operations ' | |||
, *L. F. Daughtery, Compliance Superintendent | |||
D. G.-Cupstid, Start-up Supervisor | |||
' | |||
. | |||
* | |||
R. H. McAnuity, Electrical Superintendent | |||
~R. V. Moomaw, Manager, Plant Maintenance | |||
W. P. Harris, Compliance Coordinator | |||
. | |||
*J. L. Robertson, Operations Superintendent | |||
j' L. G. Temple, I & C Superintendent | |||
; J. H. Mueller, Mechanical Superintendent | |||
, | |||
*W. E. Edge, Manager, Nuclear Site Quality Assurance | |||
*S. M..Feith, Director, Quality Assurance | |||
. | |||
Other licensee employees contacted included technicians, operators, security | |||
. force members, and office personnel. | |||
* Attended exit interview | |||
; 2. Exit Interview | |||
The inspection scope and findings were summarized on April 11, 1986, with | |||
those persons indicated in paragraph I above. The licensee did not identify | |||
4 | |||
as proprietary. any of .the' material provided to or' reviewed by the inspectors | |||
during this inspection. The_ licensee had no comment on the following | |||
;. | |||
inspection findings: | |||
a .- 416/86-08-01, Inspector Followup Item. Development of alternate | |||
methods for ensuring ADS operability. (Paragraph 4) | |||
* | |||
b. . 416/86-08-02, Inspector Followup Item. Development of a program and | |||
procedures to ensure accurate drawings and a computer system to correct | |||
the drawing legibility problem. (Paragraph 4) | |||
- | |||
' | |||
c. 416/86-08-03, Violation. Failure to ensure all operating procedures | |||
had been changed to reflect a new design change to a safety system | |||
, | |||
prior to the system being declared operable. (Paragraph 11) | |||
J | |||
$ | |||
I. | |||
i | |||
j | |||
! | |||
-- - . , _ , , , , - - - , _ , . . ~ , . . _ _ , . . . . _ _ . , . . . _ - ~ . _ _ . . - . . . -- _ _ ._. | |||
. . . _ . .. . | |||
_. _ ._- _ . . _ | |||
, | |||
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i | |||
. | |||
, | |||
2 | |||
4 | |||
y | |||
; 3. Licensee Action on Previous Enforcement Matters (92702) | |||
. a. (Closed) Violation 416/85-46-01, Failure to follow procedures. For | |||
item a., the licensee revised System Operating Instruction | |||
04-1-01-E12-1, Residual - Heat Removal System, to require approved | |||
written procedures for the unique circumstances requiring shutdown | |||
4 cooling while in mode 2. For items b. and c., the licensee discussed | |||
4 the event with operations personnel and revised the alarm Resource , | |||
j Instructions to caution operators to observe redundant instruments, | |||
b. (Closed) Deviation 416/85-45-02. The licensee has taken action to' test | |||
: and inspect the operation of the Engineered Safety Feature (ESF) room | |||
1 coolers to verify their operability. With this test and an engineering | |||
evaluation the licensee determined that the ESF room ~ coolers, even | |||
though- partially plugged,- were stili operable. The licensee has | |||
developed General Maintenance Instruction 07-S-13-56, Testing of .the | |||
: | |||
'' | |||
ESF Switchgear Room Coolers, which will periodically test ~ and inspect | |||
the coolers. This instruction will also record data for trending | |||
purposes so that the engineering department can get a better feel for | |||
~ | |||
* | |||
, | |||
how often this test should be performed. - The licensee has informed the | |||
inspectors that this test will be performed on a quarterly basis until | |||
: such time as sufficient ' data has been collected to determi.ne the | |||
correct periodicity. | |||
4. Operational Safety Verification (71707) | |||
The inspectors kept themselves informed on a daily basis of the overall | |||
plant status and any significant safety-matters related to plant operations. | |||
Daily discussions were held with plant management and various members of the | |||
* | |||
plant operating staff. | |||
The inspectors made frequent visits to the control room such that it was | |||
4 | |||
visited at least daily when an inspector was onsite. Observations included | |||
instrument readings, setpoints and recordings status of operating systems; | |||
tags and clearances on equipment controls and switches; annunciator alarms; | |||
adherence to limiting conditions for operation; temporary alterations in | |||
, | |||
effect; daily journals and data sheet entries; control room manning; and | |||
access controls. This inspection activity included numerous informal | |||
discussions with operators and their supervisors. | |||
' | |||
Weekly, when onsite, selected ESF systems were confirmed operable. The | |||
confirmation is made by verifying the following: accessible valve flow path | |||
alignment, power supply breaker and fuse status, major component leakage, | |||
, | |||
lubrication, cooling and general condition, and instrumentation. | |||
4 | |||
1 | |||
i | |||
1 | |||
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1 | |||
+ , , . _ - , . - _ - - _ , , _ _ _ . . . , _ . . . . - - , . , . _ _ . _ , - . _.._.._,..~..m_ . , _ . , . . , . , , . _ _ , . . . . . , , , , - . _ _ . _ . , _ . , , . , . - . , ~ , , - | |||
. | |||
3 | |||
General plant tours were conducted on at least a biweekly basis of portions | |||
of the control building, turbine building, auxiliary building and outside | |||
areas. Observations included safety related tagout verifications; shift | |||
turnover, sampling program, housekeeping and general plant conditions, fire | |||
protection equipment, control of . activities in progress, radiation | |||
protection controls, physical security, problem identification systems, and | |||
containment isolation. | |||
The following comments were noted: | |||
On March 19, 1986 at 11:00 a.m., the licensee recognized that excessive air | |||
flow was required to maintain the Automatic Depressurization System (ADS) at | |||
the normal operating pressure of 183 psig. The plant instrument air system | |||
with parallel booster compressors mounted outside the ADS containment | |||
penetration is used to supply the ADS air receivers and accumulators. The | |||
instrument air system is a non-safety related system. The ADS is safety | |||
related inboard from the containment outboard motor operated isolation | |||
valve. There are presently no technical specification (TS) requirements for | |||
ADS leakage. The licensee became aware of excessive stroking of the booster | |||
compressors and discovered the in-line flow meter, used for indicating an | |||
instrument air line break, was indicating a make up flow of 10 to 20 SCFM of | |||
instrument air. The licensee then conducted an air pressure drop test and | |||
the results correlated with the indicated make up flow. | |||
FSAR, paragraph 5.2.2.4.1, states that the accumulators capacity is | |||
sufficient for each ADS valve to provide two actuations against 70 percent | |||
of maximum drywell pressure. The receiver's capacity is sufficient to | |||
account for system leakage and to allow for three actuations of each ADS | |||
valve over a minimum of seven days without replenishment. Alternatively, | |||
the receiver's capacity is sufficient for 100 actuations, over a six day | |||
period, of the low-low setpoint safety / relief valve. For longer periods of | |||
time the receivers and accumulators can be recharged by utilizing compressed | |||
air cylinders and the test connection provided outside containment. The | |||
instrument air supply line from the outside containment isolation valve to | |||
the air receiver tanks is designed to the requirements of ASME Section III, | |||
Class 2 and 3, as applicable, and is seismic category 1. Based on requests | |||
for additional information, in a letter dated October 24, 1983, the licensee | |||
stated the following: | |||
a. An ADS air drop test will be acccmplished at an 18 month frequency. | |||
b. The instrument air system, including the booster compressors, are not | |||
safety related and the ADS is not dependent upon it during an accident. | |||
c. The ADS pressure is recorded every 24 hours when the system dome | |||
pressure is greater than 135 psig. | |||
d. An ADS low receiver pressure annunciator will be installed at the next | |||
refueling outage. | |||
. . - . _ . . _ _ _ _ . _ _ .- . . - _ _ _ _ . __ _ - . _ .m | |||
. | |||
* | |||
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b | |||
, | |||
4 | |||
! . | |||
, | |||
l e.. The ADS receiver and accumulator system has been analyzed assuming a | |||
; | |||
leakage rate of- 1.0 SCFH for each ADS valve on the system. There are | |||
eight ADS valves. | |||
f. The FSAR and earlier letters indicated that the system was designed to | |||
i provide three actuations of each ADS valve over a minimum period of | |||
seven days. This has been revised to five days at which time an air | |||
source will be manually connected for long term operability. | |||
. | |||
Also, in a letter dated December 20, 1982, the licensee stated that the | |||
operator round sheets would be modified to require reading a pressure gauge | |||
installed down stream of the booster compressors and if the gauge reads 150 | |||
, psig or less, the action statement of TS 3.5.1.e applies. TS 3.5.1.e states | |||
; that with two or more of the requirad ADS valves inoperable, be in at least | |||
;. hot shutdown within 12 hours and reduce reactor steam dome pressure to | |||
135 psig within the next 24 hours. As was demonstrated on March 19, 1986, | |||
the use of an ADS low receiver pressure annunciator will not insure the ADS | |||
i | |||
; is operable per the FSAR. In the event of an accident with the loss of the | |||
non-safety related instrument air system the ADS must be leak tight such | |||
'that no more than eight SCFH leakage is allowed There are no provisions . | |||
i | |||
installed or required to be installed to ensure the ADS leakage rate is | |||
monitored. | |||
The licensee shut down on March 19, 1986 and investigated the need for | |||
, | |||
excessive air makeup to the ADS. It was discovered that the accumulator | |||
! relief valves (there are 17 accumulator relief valves) were the source of | |||
leakage. One relief valve was stuck open and three others were weeping | |||
! noticeable. An analysis of the ADS showed that the relief valves have a set | |||
* | |||
pressure of 190 psig +/- 3% and reseat pressure was 10 to 15% below set | |||
pressure. The relief valves are tested for leak tightness at 90% of set | |||
' | |||
pressure or 171 psig. This would indicate, with an operating pressure of | |||
183 psig, that the relief valves were operating over their leak test | |||
' | |||
pressure and close to the lower limit of their set pressure. If a relief | |||
valve did lift due to a pressure surge, then the system pressure would have , | |||
, to be reduced to less than 161.5 psig to ensure reseating. The relief | |||
} valves are manufactured by.Lonergan. | |||
! | |||
Based on the above, the licensee removed and tested all 17 relief valves and | |||
, | |||
reduced valve leakage to no more than five bubbles per minute at 171 psig. | |||
F .The operating pressure has been revised to 165 psig. The booster compressor | |||
outlet low pressure alarm setpoint was 160 psig and required repressurizing | |||
above 173 psig to clear the alarm. A new low pressure alarm switch was | |||
installed that still alarms at 160 psig but clears at a pressure less than | |||
the new operating pressure of 165 psig. The licensee reinstalled all the | |||
~ | |||
relief valves, pressurized the ADS and leak checked all accessible | |||
, | |||
, mechanical joints. The plant returned to operation on March 24, 1986. | |||
. Although the licensee recognized a problem with excessive ADS air makeup and | |||
took appropriate actions, there are no TS surveillance requirements that | |||
. | |||
would reveal excessive makeup air demand. The licensee is investigating | |||
' | |||
alternate methods for ensuring ADS operability. This will be an Inspector | |||
' | |||
Followup Item (416/86-08-01). | |||
!- - | |||
4 | |||
: | |||
. - _ , . - - . . - , _ - . .__ - . , _ . | |||
. - - - ~ ,..- -.-. - ,__-.- -. _ _ _ , - . . | |||
, | |||
. | |||
. | |||
5 | |||
While walking down the ADS, the inspectors found the latest ADS as-built | |||
drawing, M-1067, revision 23A, was inaccurate in that air filter D024 and | |||
associated isolation valves F482, F483 and F484 were not shown although they | |||
are installed in the plant. M-1067, revision 22A, did include the filter | |||
and associated valves. Also, the drawing quality is very poor in that some | |||
parts of the drawing were almost illegible. The licensee has recognized the | |||
problem with drawing inaccuracies and legibility problems. A Plant Quality | |||
Deficiency Report was issued on February 14, 1985, describing problems with | |||
drawing inaccuracies and legibility. The licensee is presently developing a | |||
program and procedures to address and solve the problem with drawing | |||
inaccuracies. The licensee has also bought a new computer system which | |||
should correct the problem of legibility of the drawings. This computer | |||
system is expected to be fully operable after the first refueling outage | |||
scheduled to commance in September 1986. The drawing accuracy and | |||
legibility problem will be identified as an Inspector Followup Item | |||
(416/86-08-02). | |||
On March 2, 1986, during the performance of transferring recirculation pumps | |||
from 60 Hertz power to the Low Frequency Motor Generator (LFMG) sets to | |||
reduce reactor power, the B recirculation pump secured completely. The | |||
licensee's investigation revealed the output breaker for the LFMG set to the | |||
B recirculation pump failed to close. This failure was a result of the | |||
breaker's closing springs not being charged and the charging motor not being | |||
energized. The licensee determined that the last time this breaker was | |||
racked out it had not been fully racked out resulting in the closing spring | |||
not being discharged and per procedure the operator had deenergized the | |||
charging motor. Once the work was complete the breaker was racked in but | |||
the operator failed to reenergize the charging motor. Since the closing | |||
spring had not been discharged the breaker indication still showed the | |||
spring charged. The first time the breaker was given a signal to close, as | |||
it was during the previous reactor startup, it became discharged and without | |||
the charging motor energized the closing spring remained discharged. | |||
Therefore, the next time the breaker was given a signal to close, as it was | |||
on March 2, 1986, the breaker did not close resulting in the B recirculation | |||
pump securing completely. The breaker charging motor was reenergized | |||
charging the closing spring and enabling operations to place the B | |||
recirculation pump on the LFMG set without any detrimental effects to the | |||
plant. The breaker in question is a non-safety related breaker but, the | |||
circumstances leading to the failure of the breaker to close could occur on | |||
safety related breakers. The licensee has taken compensatory actions to | |||
prevent recurrence of this failure on both safety and non-safety related | |||
breakers. These actions are as follows: | |||
a. Plant Administrative procedure 01-5-06-1, Protective Tagging System, | |||
has been changed by adding the instructions, for checking the charging | |||
motor switch on and verifying the springs are charged for breakers | |||
being racked in to the red equipment clearance sheet. | |||
* | |||
. | |||
6 | |||
b. Operations Section Procedure 02-5-01-2, Control and Use of Operations | |||
Section Directives, has been changed by adding the instructions for | |||
breaker verification ensuring that the closing springs are charged and | |||
the charging motor switch is on. Breaker rack out instructions were | |||
added also, to ensure that breakers are fully racked out and the | |||
closing springs are discharged, | |||
c. The Operation Superintendent discussed this situation with all of the | |||
operating shifts. | |||
d. The Operator Training department was notified of the breaker racking ! | |||
problem and will incorporate the lessons learned into the training | |||
program, | |||
e. Operations is changing the auxiliary building, control building and | |||
turbine building round sheets to require operators to check each | |||
operable breaker weekly to verify that the charging springs are charged | |||
and the charging motor switch is on. | |||
The licensee has fully investigated and determined the cause of this event | |||
and has taken appropriate corrective actions. | |||
No violations or deviations were identified. | |||
5. Maintenance Observation (62703) | |||
During the report period, the inspector observed selected maintenance | |||
activities: The observations included a review of the work documents for | |||
adequacy, adherence to procedure, proper tagouts, adherence to technical | |||
specifications, radiological controls, observation of all or part of the | |||
actual work and/or-retesting in progress, specified retest requirements, and | |||
adherence to the appropriate quality controls. | |||
No violations or deviations were identified. | |||
6. Surveillance Testing Observation (61726) | |||
The inspector observed the performance of selected surveillances. The | |||
observation included a review of the procedure for technical adequacy, | |||
conformance to TS, verification of test instrument calibration, observation | |||
of all or part of the actual surveillances, removal from service and return | |||
to service of the system or components affected, and review of the data for | |||
-acceptability based upon the acceptance criteria. | |||
No violations or deviations were identified. | |||
, | |||
' | |||
. | |||
7 | |||
, | |||
7. ESF System Walkdown (71710) | |||
A complete walkdown was conducted on the accessible portions of the Low | |||
Pressure Core Spray (LPCS) System. The walkdown consisted of an inspection | |||
and verification, where possible, of the required system valve alignment, | |||
including valve power available and valve locking, where required; | |||
instrumentation valved in and functioning; electrical and instrumentation | |||
cabinets free from debris, loose materials, jumpers and evidence of rodents, | |||
and system free from other degrading conditions. | |||
There were no problems identified during the walkdown. However, one | |||
observation made by the inspector relates to the comments in Paragraph 4.a | |||
of this report on the illegibility of drawings. The LPCS system piping and | |||
instrumentation diagram (M1087) used by the licensee is of very poor | |||
quality. Numerous valves and instrument identification numbers are not | |||
discernible from the drawings. The inspector was able to determine the | |||
identification of these valves and instrumentation by walking down the | |||
system and comparing the as-built system to the drawing. | |||
No violations or deviations were identified. | |||
8. Reportable Occurrences (90712 & 92700) | |||
The below listed event reports were reviewed to determine if the information | |||
provided met the NRC reporting requirements. | |||
The determination included adequacy of event description and corrective | |||
action taken or planned, existence of potential generic problems and the | |||
relative safety significance of each event. Additional inplant reviews and | |||
discussions with plant personnel as appropriate were conducted for the | |||
reports indicated by an asterisk. The event reports were reviewed using the | |||
guidance of the general policy and procedure for NRC enforcement actions. | |||
The following License Event Reports (LERs) are closed. | |||
LER No. Event Date Event | |||
*86-007 February 20, 1986 Inadvertent Residual | |||
Heat Removal Pump Start | |||
*83-078 July 1, 1983 Air Relief Valve | |||
Setpoint Drift | |||
*86-004 February 12,1986 Reactor Scram During | |||
Shutdown for Excessive | |||
Coolant Leakage | |||
*86-005 February 15, 1986 Standby Gas Treatment | |||
Filter Train Heater | |||
Failed Surveillance | |||
-- | |||
- | |||
. | |||
8 | |||
. | |||
The subject of LER 86-007 was discussed in IE Report 86-04 and is tracked as | |||
violation 416/86-04-01. | |||
The subject of LER 86-004 is discussed in paragraph 9 of this inspection | |||
report. | |||
No violations or deviations were identified. | |||
9. Operating Reactor Events (93702) | |||
The inspectors reviewed activities associated with the below listed reactor | |||
events. The review included determination of cause, safety significance,- | |||
performance of personnel and systems,and corrective action. The inspectors | |||
examined instrument recordings, computer printouts, operations journal | |||
entries, scram reports and had discussions with operations maintenance and | |||
engineering support personnel as appropriate. | |||
Scram No. 38. Or February 12, 1986 unit 1 of the Grand Gulf Nuclear Station | |||
experienced a scram from approximately 13% power. At the time of the scram, | |||
the plant was in the process of being shutdown in response to TS 3.4.3.2 | |||
which requires a plant shutdown anytime unidentified leakage exceeds 5 gpm | |||
dnd cannot be corrected within a certain time period. The cause of the | |||
unidentified leakage rate exceeding 5 gpm was the partial failure of the B | |||
recirculating pump seals. | |||
At approximately 7:33 p.m. on February 12, 1986, the reactor scrammed from a | |||
low water Irvel in the vessel. This loss of level resulted from the loss of | |||
the operating reactor feed pump securing make up flow to the vessel. The | |||
apparent cause of the loss of the feed pump was due to reactor pressure | |||
exceeding feed pump discharge pressure causing a no flow situation through | |||
the feed pump. The feed pump minimum flow valve began to open in response | |||
to this no flow situation and in parallel a 15 second timer initiated. The | |||
minimum flow valve failed to open enough to allow the minimum feed pump | |||
operating flow before the 15 second timer timed out causing the feed pump to | |||
trip. Before the operators could restart either of the feed pumps the | |||
vessel level decreased below the low level scram setpoint. | |||
The licensee has determined that new valve positioners had been placed on | |||
the feed pump minimum flow valves in April of 1985. These new positioners | |||
were used because the original positioners were no longer being | |||
manufactured. When the new positioners had been installed on the minimum | |||
flow valves the overall valve operating response time was tested and found | |||
to be unchanged. However, the licensee has now discovered that with the new | |||
positioners installed the minimum flow valves will not open fast enough to | |||
the minimum operating flow position to prevent the 15 second timer from | |||
timing out, even though the over all response time is the same. The | |||
licensee has increased the delay time from 15 seconds to 30 seconds and is | |||
, | |||
investigating the possibility of obtaining new positioners which will react | |||
! much faster than the ones presently installed. | |||
No violations or deviations were identified. | |||
-- , | |||
. | |||
9 | |||
10. Inspector Followup and Unresolved Items (92701) | |||
(Closed) Inspector Followup Item 416/85-46-04. The licensee has revised | |||
Administrative Procedure 01-5-06-5, Incident Reports / Reportable Events, to | |||
clarify that significant events should be documented on an incident report | |||
even if the event is not reportable. A list of examples of conditions and | |||
situations that might not be reportable but should be considered as reeding | |||
to be documented on a incident report is provided. | |||
(Closed) Unresolved Item 416/85-45-03. This item requested the licensee | |||
provide written documentation from the pump vendor and the licensee's | |||
engineering organization, supporting the contention that 3400 gallons | |||
unusable volume was an acceptable value for determining minimum fuel oil | |||
tank level for the Emergency Diesel Generators. The licensee has provided | |||
the inspectors with a letter from Wright Masters of Crane Chempump Company | |||
to Felix Bryan of Mississippi Power and Light (MP&L) dated March 17, 1986, | |||
stating that a minimum level in the fuel oil tank of four inches above the | |||
center line of the fuel transfer pump suction flange would permit continuous | |||
pump operation. The letter went on to say that the fuel transfer pump could | |||
be operated with levels down to 0.75 inches above the pump suction flange | |||
center line but there would be a chance of shaf t journal and bearing wear. | |||
The cover mema for the above mentioned letter from F. W. Titus, Director of | |||
Nuclear Plant Engineering (NPE) to C. R. Hutchinson, GGNS General Manager | |||
dated March 29, 1986, states that four inches above the fuel transfer pump | |||
suction center line is equivalent to approximately 3,400 gallons. | |||
Therefore, the original minimum level in the fuel oil tank based on the | |||
unusable volume of 3,400 gallons was acceptable. However, in the cover memo | |||
NPE recommends that the new minimum level based on the unusable volume of | |||
8,200 gallons remain because of the possibility of damage to the fuel | |||
transfer pump if the level were allowed to drop below 3,400. | |||
11. Design, Design Changes and Modifications (37700) | |||
Design Change Package (DCP) 82/5020, Standby Service Water (SSW) Loop B | |||
System Modifications and the associated Maintenance Work Orders (MW0s) were | |||
reviewed by the inspectors. This DCP was implemented by the licensee to | |||
meet part of license conditions 2.C.20 which requires the SSW system to be | |||
modified so that design flow can be achieved to all SSW system components. | |||
The major SSW system modifications associated with this DCP include | |||
replacing the existing pump motor with a larger one, installing three new | |||
relief valves, replacing the butterfly minimum flow valve with a globe valve | |||
and modifying system supports as necessary. Each of these changes were | |||
evaluated by the licensee using the 10 CFR 50.59 process to determine if NRC | |||
review and concurrence was required and consequently all the necessary | |||
Technical Specification changes required to support the design change were | |||
submitted and approved prior to declaring the system operable | |||
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10 | |||
The inspector reviewed the MW0s listed below which implemented the DCP in | |||
the plant. This review consisted of a verification that the work was | |||
performed in accordance with established plant procedures, that all MW0s | |||
required appropriate retests and that the work was properly documented and | |||
reviewed by the Quality Assurance and Engineering organizations. | |||
MWO F 56470 Electrical Support for SSW "B" Motor | |||
Replacement | |||
MWO F 56469 Replace Cables Between D/G and Switchgear | |||
MWO F 56486 Install Relief Valves in Water Treatment | |||
Building | |||
MWO F 56488 Modify SSW B Sample Pump | |||
MWO F 55382 Rework Valves | |||
KWO F 56489 Fabrication | |||
MWO F 56487 Remove and Reinstall Pump | |||
This review did not uncover any noncompliances except for the second example | |||
of Violation 84-04-01 discussed in Inspection Report 84-04, paragraph 10. | |||
However, the inspector observed that the DCP and MWO system was very hard to | |||
follow and extremely difficult to audit due to a large number of different | |||
forms and documents used to document the work. These documents are also not | |||
filed in the same place in the vault. Therefore, ensuring that you have all | |||
of the completed records is a difficult and time consuming process. | |||
During the review of the DCP, Oesign Change Implementation Package (DCIP) | |||
and Technical Special Test Instruction (TSTI), 1P41-85-001-1-S, the | |||
inspector came across several statements requiring administrative controls | |||
be esta 411shed to verify that the minimum flow valve was locked in a | |||
positior. required to allow the proper flow rate. The DCP and the TSTI | |||
established this flow rate to be 9,500 gpm with a valve position of 43% | |||
open. Upon review of the plants System Operating Instruction (501) | |||
04-1-01-P41-1, Standby Service Water System and Surveillance Procedure (SP) | |||
06-0P-1P41-Q-0005, SSW Loop B Valve and Pump Operability Test, the inspector | |||
discovered that these procedures still reflected the old design which | |||
included a butterfly valve with a position of 30% open and a flow rate of | |||
10,500 gpm. Plant Administrative Procedure (AP) 01-S-07-4, Plant Changes | |||
and Modifications, paragraph 6.6.3 requires that all procedures requiring | |||
changes to reflect a new design must be changed prior to returning the | |||
system to operation. The SSW B system was returned to operation with the | |||
DCP incorporated in November of 1985 and the inspectors discovered that the | |||
procedures had not been changed in March of 1986. The SOI had not been | |||
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11 | |||
performed since the TSTI had been completed therefore, the minimum flow | |||
valve was left in the correct position. However, the inspectors discovered | |||
that the SP had been performed in December of 1985 and the procedure allowed | |||
operations to set the minimum flow valve position for flow rates from 9,500 | |||
gpm to 10,500 gpm. The inspectors toured the B SSW basin on March 13, 1986 | |||
to determine the actual position of the minimum flow valve and discovered | |||
the minimum flow valve position indication to be at 50% open, instead of the | |||
43% as determined in the TSTI. Discussions with the operations staff | |||
determined that the last time SP 06-0P-1P41-0-0005 was performed, the Shift | |||
Supervisor on duty was aware of TSTI IP41-85-001-1-S and instructed the | |||
operators to set the minimum flow valve at a position corresponding to 9,500 | |||
gpm. This was confirmed by operations performing a surveillance on the SSW | |||
B system and verifying the actual flow rate te be 9,500 gpm even though the | |||
valve position indication was reading 50% opsn. The concern for limiting | |||
the minimum recirculation flow is to protect the SSW pump from damage due to | |||
pump run out. The minimum flow rate was set at 9,000 +/- 500 gpm which is | |||
lower than the original 10,500 gpm due to a relief valve now being installed | |||
in the discharge line. The combination of the relief valve open and the | |||
minimum flow valve open could exceed the pump run out condition if the flow | |||
by the minimum flow valve is not limited. Operations has changed both 501 | |||
04-1-01-P41-1 and SP 06-0P-IP41-0-0005 to reflect the nroper minimum flow | |||
valve position corresponding to 9,500 gpm. | |||
TS 6.8.1 requires written procedures be established implemented and | |||
maintained covering surveillance and test activities of safety-related | |||
equipment and procedures recommended in Appendix A of Regulatory Guide 1.33, | |||
Revision 2, February 1978. Paragraph 4 of Regulatory Guide 1.33 recommends | |||
procedures for startup, operation and shutdown of safety-related BWR | |||
systems. The failure of the licensee to change 50I-04-1-01-P41-1 and SP | |||
06-0P-IP41-0-0005 to reflect the design change to the SSW B system is | |||
identified as a Violation (416/86-08-03). | |||
During the inspection of the SSW B basin, the inspectors noticed a large | |||
amount of water on the floor near the electrical switchgear and equipment | |||
located in the SSW B valve room. This water appeared to have come from the | |||
, | |||
relief valve installed in the discharge line of the B SSW system. The | |||
' | |||
inspectors notified the licensee and were informed that they were aware of a | |||
leak on the relief valve of the B SSW system and had written a Maintenance | |||
Work Order to fix the leak. However, licensee management was not aware of | |||
the large amount of water in the B SSW room. The licensee performed an | |||
operational test of the B SSW system and discovered a plug missing from the | |||
relief valve which was causing the water problem in the B SSW valve room. | |||
This plug was replaced stopping the leak licensee management has instituted | |||
a program requiring more management frequent tours of all areas of the plant | |||
to look for undesirable situations. This program was not established just | |||
as a result of this discovery but also as a result of other recent licensee | |||
identified problems. | |||
l The inspectors also reviewed the plant controlled as-built drawings and | |||
found that the changes implemented by DCP 82/5020 had been incorporated. | |||
t | |||
}} | }} |
Latest revision as of 04:05, 31 December 2020
ML20203N972 | |
Person / Time | |
---|---|
Site: | Grand Gulf ![]() |
Issue date: | 04/22/1986 |
From: | Butcher R, Caldwell J, Dance H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
To: | |
Shared Package | |
ML20203N954 | List: |
References | |
50-416-86-08, 50-416-86-8, NUDOCS 8605060245 | |
Download: ML20203N972 (12) | |
See also: IR 05000416/1986008
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UNIT ED STATES
_ [p 8 42 lo,^
NUCLEAR REGULATORY COMMISSION
O REGION 11
'3* .
101 MARIETTA STREET.N.W.
- - ATLANTA. GEORGI A 30323
\...../
Report No.: 50-416/86-08
Licensee: Mississippi Power And Light Company
Jackson, MS 39205-
Docket No.: 50-416 License No.: NPF-29
Facility Name: Grand Gulf 1
Inspection Conducted: Ma ch 18 - April 14,1986
Inspe ors: } 's ** 3 42l
' p R. C. Butcher Senior Resident inspector
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Date Signed
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19Al k
,yt,-J. L. Caldwell, Resident Inspector
A,In
Date Signed
Approved by: h <>- - ,
2 LkS
H'. C. Ornte, Section Chief Date Si'gned
Division of Reactor Projects
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SUMMARY
Scope: This routine inspection entailed 155 resident inspector-hours at the site
in the areas of Operational Safety Verification, Maintenance Observation,
, Surveillance Observation, Engineering Safety Feature System Walkdown, Reportable
Occurrences, Operating Reactor Events, Inspector Followup -and Unresolved Items,
and Design Changes and Modifications.
Results: One violation - Failure to change operating procedures affected by a
design change to a safety related system prior to the system being declared
.
8605060245 860423 6
PDR ADOCK 0500
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REPORT DETAILS
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- 1. Licensee Employees Contacted
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4 J. E. Cross, Site Director
- C. R. Hutchinson, General Manager
- R. F. Rogers, Technical Assistant
- J. D. Bailey, Compliance Coordinator
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- M. J. Wright, Manager, Plant Operations '
, *L. F. Daughtery, Compliance Superintendent
D. G.-Cupstid, Start-up Supervisor
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R. H. McAnuity, Electrical Superintendent
~R. V. Moomaw, Manager, Plant Maintenance
W. P. Harris, Compliance Coordinator
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- J. L. Robertson, Operations Superintendent
j' L. G. Temple, I & C Superintendent
- J. H. Mueller, Mechanical Superintendent
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- W. E. Edge, Manager, Nuclear Site Quality Assurance
- S. M..Feith, Director, Quality Assurance
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Other licensee employees contacted included technicians, operators, security
. force members, and office personnel.
- Attended exit interview
- 2. Exit Interview
The inspection scope and findings were summarized on April 11, 1986, with
those persons indicated in paragraph I above. The licensee did not identify
4
as proprietary. any of .the' material provided to or' reviewed by the inspectors
during this inspection. The_ licensee had no comment on the following
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inspection findings:
a .- 416/86-08-01, Inspector Followup Item. Development of alternate
methods for ensuring ADS operability. (Paragraph 4)
b. . 416/86-08-02, Inspector Followup Item. Development of a program and
procedures to ensure accurate drawings and a computer system to correct
the drawing legibility problem. (Paragraph 4)
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c. 416/86-08-03, Violation. Failure to ensure all operating procedures
had been changed to reflect a new design change to a safety system
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prior to the system being declared operable. (Paragraph 11)
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- 3. Licensee Action on Previous Enforcement Matters (92702)
. a. (Closed) Violation 416/85-46-01, Failure to follow procedures. For
item a., the licensee revised System Operating Instruction
04-1-01-E12-1, Residual - Heat Removal System, to require approved
written procedures for the unique circumstances requiring shutdown
4 cooling while in mode 2. For items b. and c., the licensee discussed
4 the event with operations personnel and revised the alarm Resource ,
j Instructions to caution operators to observe redundant instruments,
b. (Closed) Deviation 416/85-45-02. The licensee has taken action to' test
- and inspect the operation of the Engineered Safety Feature (ESF) room
1 coolers to verify their operability. With this test and an engineering
evaluation the licensee determined that the ESF room ~ coolers, even
though- partially plugged,- were stili operable. The licensee has
developed General Maintenance Instruction 07-S-13-56, Testing of .the
ESF Switchgear Room Coolers, which will periodically test ~ and inspect
the coolers. This instruction will also record data for trending
purposes so that the engineering department can get a better feel for
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how often this test should be performed. - The licensee has informed the
inspectors that this test will be performed on a quarterly basis until
- such time as sufficient ' data has been collected to determi.ne the
correct periodicity.
4. Operational Safety Verification (71707)
The inspectors kept themselves informed on a daily basis of the overall
plant status and any significant safety-matters related to plant operations.
Daily discussions were held with plant management and various members of the
plant operating staff.
The inspectors made frequent visits to the control room such that it was
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visited at least daily when an inspector was onsite. Observations included
instrument readings, setpoints and recordings status of operating systems;
tags and clearances on equipment controls and switches; annunciator alarms;
adherence to limiting conditions for operation; temporary alterations in
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effect; daily journals and data sheet entries; control room manning; and
access controls. This inspection activity included numerous informal
discussions with operators and their supervisors.
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Weekly, when onsite, selected ESF systems were confirmed operable. The
confirmation is made by verifying the following: accessible valve flow path
alignment, power supply breaker and fuse status, major component leakage,
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lubrication, cooling and general condition, and instrumentation.
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General plant tours were conducted on at least a biweekly basis of portions
of the control building, turbine building, auxiliary building and outside
areas. Observations included safety related tagout verifications; shift
turnover, sampling program, housekeeping and general plant conditions, fire
protection equipment, control of . activities in progress, radiation
protection controls, physical security, problem identification systems, and
containment isolation.
The following comments were noted:
On March 19, 1986 at 11:00 a.m., the licensee recognized that excessive air
flow was required to maintain the Automatic Depressurization System (ADS) at
the normal operating pressure of 183 psig. The plant instrument air system
with parallel booster compressors mounted outside the ADS containment
penetration is used to supply the ADS air receivers and accumulators. The
instrument air system is a non-safety related system. The ADS is safety
related inboard from the containment outboard motor operated isolation
valve. There are presently no technical specification (TS) requirements for
ADS leakage. The licensee became aware of excessive stroking of the booster
compressors and discovered the in-line flow meter, used for indicating an
instrument air line break, was indicating a make up flow of 10 to 20 SCFM of
instrument air. The licensee then conducted an air pressure drop test and
the results correlated with the indicated make up flow.
FSAR, paragraph 5.2.2.4.1, states that the accumulators capacity is
sufficient for each ADS valve to provide two actuations against 70 percent
of maximum drywell pressure. The receiver's capacity is sufficient to
account for system leakage and to allow for three actuations of each ADS
valve over a minimum of seven days without replenishment. Alternatively,
the receiver's capacity is sufficient for 100 actuations, over a six day
period, of the low-low setpoint safety / relief valve. For longer periods of
time the receivers and accumulators can be recharged by utilizing compressed
air cylinders and the test connection provided outside containment. The
instrument air supply line from the outside containment isolation valve to
the air receiver tanks is designed to the requirements of ASME Section III,
Class 2 and 3, as applicable, and is seismic category 1. Based on requests
for additional information, in a letter dated October 24, 1983, the licensee
stated the following:
a. An ADS air drop test will be acccmplished at an 18 month frequency.
b. The instrument air system, including the booster compressors, are not
safety related and the ADS is not dependent upon it during an accident.
c. The ADS pressure is recorded every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when the system dome
pressure is greater than 135 psig.
d. An ADS low receiver pressure annunciator will be installed at the next
refueling outage.
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l e.. The ADS receiver and accumulator system has been analyzed assuming a
leakage rate of- 1.0 SCFH for each ADS valve on the system. There are
eight ADS valves.
f. The FSAR and earlier letters indicated that the system was designed to
i provide three actuations of each ADS valve over a minimum period of
seven days. This has been revised to five days at which time an air
source will be manually connected for long term operability.
.
Also, in a letter dated December 20, 1982, the licensee stated that the
operator round sheets would be modified to require reading a pressure gauge
installed down stream of the booster compressors and if the gauge reads 150
, psig or less, the action statement of TS 3.5.1.e applies. TS 3.5.1.e states
- that with two or more of the requirad ADS valves inoperable, be in at least
- . hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to
135 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. As was demonstrated on March 19, 1986,
the use of an ADS low receiver pressure annunciator will not insure the ADS
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non-safety related instrument air system the ADS must be leak tight such
'that no more than eight SCFH leakage is allowed There are no provisions .
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installed or required to be installed to ensure the ADS leakage rate is
monitored.
The licensee shut down on March 19, 1986 and investigated the need for
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excessive air makeup to the ADS. It was discovered that the accumulator
! relief valves (there are 17 accumulator relief valves) were the source of
leakage. One relief valve was stuck open and three others were weeping
! noticeable. An analysis of the ADS showed that the relief valves have a set
pressure of 190 psig +/- 3% and reseat pressure was 10 to 15% below set
pressure. The relief valves are tested for leak tightness at 90% of set
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pressure or 171 psig. This would indicate, with an operating pressure of
183 psig, that the relief valves were operating over their leak test
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pressure and close to the lower limit of their set pressure. If a relief
valve did lift due to a pressure surge, then the system pressure would have ,
, to be reduced to less than 161.5 psig to ensure reseating. The relief
} valves are manufactured by.Lonergan.
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Based on the above, the licensee removed and tested all 17 relief valves and
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reduced valve leakage to no more than five bubbles per minute at 171 psig.
F .The operating pressure has been revised to 165 psig. The booster compressor
outlet low pressure alarm setpoint was 160 psig and required repressurizing
above 173 psig to clear the alarm. A new low pressure alarm switch was
installed that still alarms at 160 psig but clears at a pressure less than
the new operating pressure of 165 psig. The licensee reinstalled all the
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relief valves, pressurized the ADS and leak checked all accessible
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, mechanical joints. The plant returned to operation on March 24, 1986.
. Although the licensee recognized a problem with excessive ADS air makeup and
took appropriate actions, there are no TS surveillance requirements that
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would reveal excessive makeup air demand. The licensee is investigating
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alternate methods for ensuring ADS operability. This will be an Inspector
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Followup Item (416/86-08-01).
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While walking down the ADS, the inspectors found the latest ADS as-built
drawing, M-1067, revision 23A, was inaccurate in that air filter D024 and
associated isolation valves F482, F483 and F484 were not shown although they
are installed in the plant. M-1067, revision 22A, did include the filter
and associated valves. Also, the drawing quality is very poor in that some
parts of the drawing were almost illegible. The licensee has recognized the
problem with drawing inaccuracies and legibility problems. A Plant Quality
Deficiency Report was issued on February 14, 1985, describing problems with
drawing inaccuracies and legibility. The licensee is presently developing a
program and procedures to address and solve the problem with drawing
inaccuracies. The licensee has also bought a new computer system which
should correct the problem of legibility of the drawings. This computer
system is expected to be fully operable after the first refueling outage
scheduled to commance in September 1986. The drawing accuracy and
legibility problem will be identified as an Inspector Followup Item
(416/86-08-02).
On March 2, 1986, during the performance of transferring recirculation pumps
from 60 Hertz power to the Low Frequency Motor Generator (LFMG) sets to
reduce reactor power, the B recirculation pump secured completely. The
licensee's investigation revealed the output breaker for the LFMG set to the
B recirculation pump failed to close. This failure was a result of the
breaker's closing springs not being charged and the charging motor not being
energized. The licensee determined that the last time this breaker was
racked out it had not been fully racked out resulting in the closing spring
not being discharged and per procedure the operator had deenergized the
charging motor. Once the work was complete the breaker was racked in but
the operator failed to reenergize the charging motor. Since the closing
spring had not been discharged the breaker indication still showed the
spring charged. The first time the breaker was given a signal to close, as
it was during the previous reactor startup, it became discharged and without
the charging motor energized the closing spring remained discharged.
Therefore, the next time the breaker was given a signal to close, as it was
on March 2, 1986, the breaker did not close resulting in the B recirculation
pump securing completely. The breaker charging motor was reenergized
charging the closing spring and enabling operations to place the B
recirculation pump on the LFMG set without any detrimental effects to the
plant. The breaker in question is a non-safety related breaker but, the
circumstances leading to the failure of the breaker to close could occur on
safety related breakers. The licensee has taken compensatory actions to
prevent recurrence of this failure on both safety and non-safety related
breakers. These actions are as follows:
a. Plant Administrative procedure 01-5-06-1, Protective Tagging System,
has been changed by adding the instructions, for checking the charging
motor switch on and verifying the springs are charged for breakers
being racked in to the red equipment clearance sheet.
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6
b. Operations Section Procedure 02-5-01-2, Control and Use of Operations
Section Directives, has been changed by adding the instructions for
breaker verification ensuring that the closing springs are charged and
the charging motor switch is on. Breaker rack out instructions were
added also, to ensure that breakers are fully racked out and the
closing springs are discharged,
c. The Operation Superintendent discussed this situation with all of the
operating shifts.
d. The Operator Training department was notified of the breaker racking !
problem and will incorporate the lessons learned into the training
program,
e. Operations is changing the auxiliary building, control building and
turbine building round sheets to require operators to check each
operable breaker weekly to verify that the charging springs are charged
and the charging motor switch is on.
The licensee has fully investigated and determined the cause of this event
and has taken appropriate corrective actions.
No violations or deviations were identified.
5. Maintenance Observation (62703)
During the report period, the inspector observed selected maintenance
activities: The observations included a review of the work documents for
adequacy, adherence to procedure, proper tagouts, adherence to technical
specifications, radiological controls, observation of all or part of the
actual work and/or-retesting in progress, specified retest requirements, and
adherence to the appropriate quality controls.
No violations or deviations were identified.
6. Surveillance Testing Observation (61726)
The inspector observed the performance of selected surveillances. The
observation included a review of the procedure for technical adequacy,
conformance to TS, verification of test instrument calibration, observation
of all or part of the actual surveillances, removal from service and return
to service of the system or components affected, and review of the data for
-acceptability based upon the acceptance criteria.
No violations or deviations were identified.
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7. ESF System Walkdown (71710)
A complete walkdown was conducted on the accessible portions of the Low
Pressure Core Spray (LPCS) System. The walkdown consisted of an inspection
and verification, where possible, of the required system valve alignment,
including valve power available and valve locking, where required;
instrumentation valved in and functioning; electrical and instrumentation
cabinets free from debris, loose materials, jumpers and evidence of rodents,
and system free from other degrading conditions.
There were no problems identified during the walkdown. However, one
observation made by the inspector relates to the comments in Paragraph 4.a
of this report on the illegibility of drawings. The LPCS system piping and
instrumentation diagram (M1087) used by the licensee is of very poor
quality. Numerous valves and instrument identification numbers are not
discernible from the drawings. The inspector was able to determine the
identification of these valves and instrumentation by walking down the
system and comparing the as-built system to the drawing.
No violations or deviations were identified.
8. Reportable Occurrences (90712 & 92700)
The below listed event reports were reviewed to determine if the information
provided met the NRC reporting requirements.
The determination included adequacy of event description and corrective
action taken or planned, existence of potential generic problems and the
relative safety significance of each event. Additional inplant reviews and
discussions with plant personnel as appropriate were conducted for the
reports indicated by an asterisk. The event reports were reviewed using the
guidance of the general policy and procedure for NRC enforcement actions.
The following License Event Reports (LERs) are closed.
LER No. Event Date Event
- 86-007 February 20, 1986 Inadvertent Residual
Heat Removal Pump Start
- 83-078 July 1, 1983 Air Relief Valve
Setpoint Drift
- 86-004 February 12,1986 Reactor Scram During
Shutdown for Excessive
Coolant Leakage
- 86-005 February 15, 1986 Standby Gas Treatment
Filter Train Heater
Failed Surveillance
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The subject of LER 86-007 was discussed in IE Report 86-04 and is tracked as
violation 416/86-04-01.
The subject of LER 86-004 is discussed in paragraph 9 of this inspection
report.
No violations or deviations were identified.
9. Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed reactor
events. The review included determination of cause, safety significance,-
performance of personnel and systems,and corrective action. The inspectors
examined instrument recordings, computer printouts, operations journal
entries, scram reports and had discussions with operations maintenance and
engineering support personnel as appropriate.
Scram No. 38. Or February 12, 1986 unit 1 of the Grand Gulf Nuclear Station
experienced a scram from approximately 13% power. At the time of the scram,
the plant was in the process of being shutdown in response to TS 3.4.3.2
which requires a plant shutdown anytime unidentified leakage exceeds 5 gpm
dnd cannot be corrected within a certain time period. The cause of the
unidentified leakage rate exceeding 5 gpm was the partial failure of the B
recirculating pump seals.
At approximately 7:33 p.m. on February 12, 1986, the reactor scrammed from a
low water Irvel in the vessel. This loss of level resulted from the loss of
the operating reactor feed pump securing make up flow to the vessel. The
apparent cause of the loss of the feed pump was due to reactor pressure
exceeding feed pump discharge pressure causing a no flow situation through
the feed pump. The feed pump minimum flow valve began to open in response
to this no flow situation and in parallel a 15 second timer initiated. The
minimum flow valve failed to open enough to allow the minimum feed pump
operating flow before the 15 second timer timed out causing the feed pump to
trip. Before the operators could restart either of the feed pumps the
vessel level decreased below the low level scram setpoint.
The licensee has determined that new valve positioners had been placed on
the feed pump minimum flow valves in April of 1985. These new positioners
were used because the original positioners were no longer being
manufactured. When the new positioners had been installed on the minimum
flow valves the overall valve operating response time was tested and found
to be unchanged. However, the licensee has now discovered that with the new
positioners installed the minimum flow valves will not open fast enough to
the minimum operating flow position to prevent the 15 second timer from
timing out, even though the over all response time is the same. The
licensee has increased the delay time from 15 seconds to 30 seconds and is
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investigating the possibility of obtaining new positioners which will react
! much faster than the ones presently installed.
No violations or deviations were identified.
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10. Inspector Followup and Unresolved Items (92701)
(Closed) Inspector Followup Item 416/85-46-04. The licensee has revised
Administrative Procedure 01-5-06-5, Incident Reports / Reportable Events, to
clarify that significant events should be documented on an incident report
even if the event is not reportable. A list of examples of conditions and
situations that might not be reportable but should be considered as reeding
to be documented on a incident report is provided.
(Closed) Unresolved Item 416/85-45-03. This item requested the licensee
provide written documentation from the pump vendor and the licensee's
engineering organization, supporting the contention that 3400 gallons
unusable volume was an acceptable value for determining minimum fuel oil
tank level for the Emergency Diesel Generators. The licensee has provided
the inspectors with a letter from Wright Masters of Crane Chempump Company
to Felix Bryan of Mississippi Power and Light (MP&L) dated March 17, 1986,
stating that a minimum level in the fuel oil tank of four inches above the
center line of the fuel transfer pump suction flange would permit continuous
pump operation. The letter went on to say that the fuel transfer pump could
be operated with levels down to 0.75 inches above the pump suction flange
center line but there would be a chance of shaf t journal and bearing wear.
The cover mema for the above mentioned letter from F. W. Titus, Director of
Nuclear Plant Engineering (NPE) to C. R. Hutchinson, GGNS General Manager
dated March 29, 1986, states that four inches above the fuel transfer pump
suction center line is equivalent to approximately 3,400 gallons.
Therefore, the original minimum level in the fuel oil tank based on the
unusable volume of 3,400 gallons was acceptable. However, in the cover memo
NPE recommends that the new minimum level based on the unusable volume of
8,200 gallons remain because of the possibility of damage to the fuel
transfer pump if the level were allowed to drop below 3,400.
11. Design, Design Changes and Modifications (37700)
Design Change Package (DCP) 82/5020, Standby Service Water (SSW) Loop B
System Modifications and the associated Maintenance Work Orders (MW0s) were
reviewed by the inspectors. This DCP was implemented by the licensee to
meet part of license conditions 2.C.20 which requires the SSW system to be
modified so that design flow can be achieved to all SSW system components.
The major SSW system modifications associated with this DCP include
replacing the existing pump motor with a larger one, installing three new
relief valves, replacing the butterfly minimum flow valve with a globe valve
and modifying system supports as necessary. Each of these changes were
evaluated by the licensee using the 10 CFR 50.59 process to determine if NRC
review and concurrence was required and consequently all the necessary
Technical Specification changes required to support the design change were
submitted and approved prior to declaring the system operable
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The inspector reviewed the MW0s listed below which implemented the DCP in
the plant. This review consisted of a verification that the work was
performed in accordance with established plant procedures, that all MW0s
required appropriate retests and that the work was properly documented and
reviewed by the Quality Assurance and Engineering organizations.
MWO F 56470 Electrical Support for SSW "B" Motor
Replacement
MWO F 56469 Replace Cables Between D/G and Switchgear
MWO F 56486 Install Relief Valves in Water Treatment
Building
MWO F 56488 Modify SSW B Sample Pump
MWO F 55382 Rework Valves
KWO F 56489 Fabrication
MWO F 56487 Remove and Reinstall Pump
This review did not uncover any noncompliances except for the second example
of Violation 84-04-01 discussed in Inspection Report 84-04, paragraph 10.
However, the inspector observed that the DCP and MWO system was very hard to
follow and extremely difficult to audit due to a large number of different
forms and documents used to document the work. These documents are also not
filed in the same place in the vault. Therefore, ensuring that you have all
of the completed records is a difficult and time consuming process.
During the review of the DCP, Oesign Change Implementation Package (DCIP)
and Technical Special Test Instruction (TSTI), 1P41-85-001-1-S, the
inspector came across several statements requiring administrative controls
be esta 411shed to verify that the minimum flow valve was locked in a
positior. required to allow the proper flow rate. The DCP and the TSTI
established this flow rate to be 9,500 gpm with a valve position of 43%
open. Upon review of the plants System Operating Instruction (501)
04-1-01-P41-1, Standby Service Water System and Surveillance Procedure (SP)
06-0P-1P41-Q-0005, SSW Loop B Valve and Pump Operability Test, the inspector
discovered that these procedures still reflected the old design which
included a butterfly valve with a position of 30% open and a flow rate of
10,500 gpm. Plant Administrative Procedure (AP) 01-S-07-4, Plant Changes
and Modifications, paragraph 6.6.3 requires that all procedures requiring
changes to reflect a new design must be changed prior to returning the
system to operation. The SSW B system was returned to operation with the
DCP incorporated in November of 1985 and the inspectors discovered that the
procedures had not been changed in March of 1986. The SOI had not been
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performed since the TSTI had been completed therefore, the minimum flow
valve was left in the correct position. However, the inspectors discovered
that the SP had been performed in December of 1985 and the procedure allowed
operations to set the minimum flow valve position for flow rates from 9,500
gpm to 10,500 gpm. The inspectors toured the B SSW basin on March 13, 1986
to determine the actual position of the minimum flow valve and discovered
the minimum flow valve position indication to be at 50% open, instead of the
43% as determined in the TSTI. Discussions with the operations staff
determined that the last time SP 06-0P-1P41-0-0005 was performed, the Shift
Supervisor on duty was aware of TSTI IP41-85-001-1-S and instructed the
operators to set the minimum flow valve at a position corresponding to 9,500
gpm. This was confirmed by operations performing a surveillance on the SSW
B system and verifying the actual flow rate te be 9,500 gpm even though the
valve position indication was reading 50% opsn. The concern for limiting
the minimum recirculation flow is to protect the SSW pump from damage due to
pump run out. The minimum flow rate was set at 9,000 +/- 500 gpm which is
lower than the original 10,500 gpm due to a relief valve now being installed
in the discharge line. The combination of the relief valve open and the
minimum flow valve open could exceed the pump run out condition if the flow
by the minimum flow valve is not limited. Operations has changed both 501
04-1-01-P41-1 and SP 06-0P-IP41-0-0005 to reflect the nroper minimum flow
valve position corresponding to 9,500 gpm.
TS 6.8.1 requires written procedures be established implemented and
maintained covering surveillance and test activities of safety-related
equipment and procedures recommended in Appendix A of Regulatory Guide 1.33,
Revision 2, February 1978. Paragraph 4 of Regulatory Guide 1.33 recommends
procedures for startup, operation and shutdown of safety-related BWR
systems. The failure of the licensee to change 50I-04-1-01-P41-1 and SP
06-0P-IP41-0-0005 to reflect the design change to the SSW B system is
identified as a Violation (416/86-08-03).
During the inspection of the SSW B basin, the inspectors noticed a large
amount of water on the floor near the electrical switchgear and equipment
located in the SSW B valve room. This water appeared to have come from the
,
relief valve installed in the discharge line of the B SSW system. The
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inspectors notified the licensee and were informed that they were aware of a
leak on the relief valve of the B SSW system and had written a Maintenance
Work Order to fix the leak. However, licensee management was not aware of
the large amount of water in the B SSW room. The licensee performed an
operational test of the B SSW system and discovered a plug missing from the
relief valve which was causing the water problem in the B SSW valve room.
This plug was replaced stopping the leak licensee management has instituted
a program requiring more management frequent tours of all areas of the plant
to look for undesirable situations. This program was not established just
as a result of this discovery but also as a result of other recent licensee
identified problems.
l The inspectors also reviewed the plant controlled as-built drawings and
found that the changes implemented by DCP 82/5020 had been incorporated.
t