Text

Insp Repts 50-327/93-13 & 50-328/93-13 on 930404-0501. Violations Identified But Not Subj to Enforcement Action. Major Areas Inspected:Plant Operations,Maint & Surveillance & Evaluation of Licensee self-assessment Capability
	ML20036C329
Person / Time
Site:	Sequoyah
Issue date:	05/14/1993
From:	Holland W, Kellogg P; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20036C325	List: IR 05000327/1993013; ML20036C324;
References
	50-327-93-13, 50-328-93-13, NUDOCS 9306160127
	Download: ML20036C329 (30)
	v • d • e

.

- "%

c UNITED STATES

,o NUCLEAR REGULATORY COMMisslON l

p7 n

REGION It j

101 MARIETTA STRE ET N.W.

..

j

't ATLANTA. GEORGI A 30323

\\....+/

'

i

-

i

,

Report Nos.: 50-327/93-13 and 50-328/93-13

'

Licensee: Tennessee Valley Authority

6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.:

50-327 and 50-328 License Nos.: DPR-77 and DPR-79 Facility Name: Sequoyah Units 1 and 2 Inspection Conducted: April 4 through May 1,1993 i

gl'

/

\\

/

Lead Inspector:

G G- /ft/

f/ /7/ 65

..

_

E i

W.f.HoMa enior Residenyns.pector Date Signed i

Inspectors:

S. M. Shaeffer, Resident Inspector A. R. Long, Resident Inspector S. E. Spar Project Engineer l

,

Approved by:

,.

__[

/[

Patp/ h ellogg,_

Date Signed Diyision of Regc p

'et, Sectich 4A r Projects SUMMARY

,

Scope:

!

This routine resident inspection was conducted on site in the areas of plant operations, plant maintenance, plant surveillance, evaluation of licensee self-assessment capability, licensee event report closecut, and followup on i

previous inspection findings.. During the performance of this inspection, the

resident inspectors conducted several reviews of the licensee's backshift or

'

weekend operations.

,

i

,

9306160127 930526 PDR ADOCK 05000327 G

PDR

,

~

_

._

-.

._

.-

A

.

.-

,

t

[

'

l

!

Results:

'

In the area of Radiological Controls, a strength was identified with

,

regard to good management oversight.and ALARA planning which resulted in a low person-rem expenditure for the Unit I core barrel removal

r (paragraph 3.b.2).

-

In the area of Maintenance, a Non-cited violation for failure to follow the requirements of TS 6.8.1 was identified with regard to the erection of scaffolding in safety-related areas (paragraph 3.b.3).

i Reviews of licensee outage performance were conducted in several functional areas during this period (paragraph 3.g).

Operations

,

performance was mixed with good control being maintained for system

,

configurations during outage activities.

However, operator sensitivity to reactor coolant system level prior to system draindown was considered

'

to be weak.

Radiological controls performance was considered to be very good with person-rem expenditure below projected levels.

Engineering performance was mixed with system and design engineers providing good

support of restart activities. However, specific review areas indicated

'

that engineering support could have been better.

-

,

In the area of Safety Assessment, a weakness was identified with regard

'

to operations personnel not consistently and routinely considering the

,

FSAR when reviewing abnormal configurations and equipment problems (paragraph 4.b).

,

i

>

t i

!

l i

f

!

i P

1

.

. -, -

.

-

. -

.

-

- -

-

_

~-

i

.

v

.

,

i REPORT. DETAILS

!

1.

Persons Contacted

'

Licensee Employees l

.

R. Fenech, Site Vice President

R. Beecken, Plant Manager

,

L. Bryant, Maintenance Manager

,'

J. Baumstark, Operations Manager M. Cooper, Site Licensing Manager

'

T. Flippo, Site Quality Assurance Manager

J. Gates, Outage Manager

C. Kent, Chemistry and Radiological Control Manager

,

R. Rausch, Modifications Manager

D. Lundy, Technical Support Manager

B. Schofield, Acting Site Licensing Manager J. Smith, Regulatory Licensing Manager l

R. Thompson, Compliance Licensing Manager

P. Trudel, Nuclear _ Engineering Manager

J. Ward, Engineering and Modifications Manager

N. Welch, Operations Superintendent NRC Employees I

P P. Kellogg, Chief, DRP Section 4A f

Attended exit interview.

Other licensee employees contacted included control room operators,

'

shift technical advisors, shift supervisors and other plant personnel.

Acronyms and initialisms used in this report are listed in the last paragraph.

On April 5, 1993, the NRC Restart Panel was on site to discuss restart activities with licensee senior management.

During the week of April 5-9, 1993, the Sequoyah Project Engineer, Mr.

Scott Sparks, was on site for inspection activities.

On April 8,1993, the licensee informed the resident inspectors of the following management changes: Mr. Ron Eytchison was named Vice President, Nuclear Operations. Dr. Mark Medford was named Vice President, Technical Support. All corporate nuclear functions are being consolidated in technical support organization including Corporate Engineering and Modifications, Operations Services, Nuclear Business i

Operations and Concerns Resolution, and Nuclear Assurance, Licensing and i

Fuels.

'

On April 12, 1993 Ms. Rebecca Long reported to the site for a six-month assignment as a resident inspector.

i

..

-

.

__

_ __

_

. _ -

,

Y

.

o l

-

t i

'

i On April 22 and 23, Mr. Paul Kellogg, the NRC, RII Section Chief was on site. Mr Kellogg discussed current issues with the resident inspectors,

met with licensee management, attended two NRC inspection exit meetings,

and toured the plant with the resident inspectors.

l t

2.

Plant Status l

Unit I began the inspection period in MODE 5 (Day 33 of a forced

!

outage). On April 8, 1993 the unit began its Cycle 6 refueling outage.

Refueling preparations continued early in the period with the unit

=

entering MODE 6 on April 11, 1993.

Fuel offload commenced on April 18 and was completed on April 20, 1993. Ten year ISI inspections of the

reactor vessel were in progress when the report period ended.

,

Unit 2 began the inspection period in MODE 5 (Day 34 of a forced outage).

During the period activities continued with regard to piping

!

replacement in the secondary plant due to erosion.

In addition, other items identified as required for restart of the unit were also worked.

At the end of the period, Unit 2 remained in MODE 5 with work ongoing in accordance with the licensee's forced outage schedule.

,

3.

Operational Safety Verification (71707)

a.

Daily Inspections The inspectors conducted daily inspections in the following areas:

control room staffing, access, and operator behavior; operator

adherence to approved procedures, TS, and LCOs; examination of

panels containing instrumentation and other reactor protection

system elements to determine that' required channels are operable-and review of control room operator logs, operating orders, plant

.

deviation reports, tagout logs, temporary modification logs, and

tags on components to verify compliance with approved procedures.

!

The inspectors also routinely accompanied plant management on

-

plant tours and observed the effectiveness of management's influence on activities being performed by plant personnel.

On April 10, 1993 the inspectors were informed of a problem that

!

was identified during the Unit I draindown in preparation for i

reactor vessel disassembly.

The problem, which was observed on

,

April 9, involved an unknown loss of RCS level indication due to

!

the failure of the pressurizer cold calibration level channel.

The failure was discovered by the operators when they were placing

,

in service the liquid level instrument in accordance with system operating instruction 0-50-68-4, DRAINING REACTOR COOLANT SYSTEM, i

Revision 9.

During performance of step 6.1 [27] of the 50,

!

operators noticed that the liquid level gage indicated that the

RCS level was approximately elevation 701 (approximately 1 foot

-

below reactor vessel flange level) while pressurizer cold

calibration level channel (LI-68-321) indicated a level of

'

approximately 9% which would correlate to elevation 716.

!

i

_ _,

,

_

,_

_

_4

>

.

,

..

Operators took action to add water to the RCS and noted that the liquid level indication increased. They did not notice any

,

increase in level on the pressurizer level instrument during this period. Operators then decided to' valve in the RCS level sightglass to provide an additional means to determine RCS level.

The sightglass confirmed that RCS level was approximately

,

elevation 703. Troubleshooting was accomplished on pressurizer instrument LI-68-321 and it was determined that the reference leg l

had become partially drained resulting in incorrect RCS level

indication from this instrument.

Partial drain of the instrument was attributed to leakage past an instrument vent valve.

The licensee initiated a work request to repair the valve, and

initiated an incident investigation to review this event.

The inspectors will review the II report for corrective actions.

The inspectors reviewed licensee procedures in the control room on February 10 and noted that operators were recording RCS level for Unit I using both the liquid level gage and the standpipe'as

,

required by 0-PI-0PS-068-673.S, LEVEL VERIFICATION FOR THE REACTOR COOLANT SYSTEM, Rev. 2.

The inspectors determined that recording activities were in accordance with the procedure.

However, some steps in the prerequisite actions portion of the procedure had not been performed or N/Aed. The inspectors were informed that the procedural steps in question were not applicable to the present condition. A procedure change was processed to remove the steps during the next four hours.

The. inspectors conducted additional reviews of 0-S0-68-4 over the next few days. The inspectors discussed the S0 with operations personnel on April 19.

During these discussions the inspectors questioned two precautions and limitations statements which were unclear to both the inspectors and operations personnel in.the meeting. Also, the inspectors noted that limited initial ~

conditions were required prior to starting the normal operation portion of the procedure.

,

During the S0 review the inspectors specifically noted the following:

,

-

No calibration was required of LI-68-321 other than the normal routine calibration which had been accomplished on

January 21, 1993.

-

RVLIS was one means of providing level indication for draindown. However, this system was not in use due to unavailability. This area is further discussed in paragraph 5.

-

Several areas in the procedure allow for purging of different RCS components (Pressurizer, PRT, Reactor Vessel

,

t Head). The inspectors determined that the design for providing temporary level indications did not provide for

,

I

r

'

.

s

.,

connections which could compensate for different pressures throughout the RCS. This condition required specific-i operator understanding of the effects of the purging evolutions on RCS indicated level.

The inspectors concluded that adequate RCS level control was being implemented by operators after the event occurred. However, prior to determination of actual RCS level being slightly below the RCS flange on April 9,1993, over 10,000 gallons of RCS inventory had been unknowingly drained from the RCS due to the pressurizer cold calibration level instrument being inoperable due to the reference leg being partially drained.

In addition, although procedural controls recommend that two means of level indication be available during draindown, this condition diu not exist, in part, due to RVLIS not being available.

This event exhibited a lack of sensitivity to an evolution important to safety, in that operators did not recognize the cold calibrated pressurized level instrument was indicating improperly,

,

and did not ensure the reliability of the cold calibrated pressurized level channel prior to use.

In addition, a decision was made to not have the Reactor Vessel Level Indication System available, which hampered operations' ability to accurately determine reactor water level.

.

b.

Weekly Inspections The inspectors conducted weekly inspections in the following areas: operability verification of selected ESF systems by valve alignment, breaker positions, condition of equipment or component,

>

and operability of instrumentation and support items essential to system actuation or performance.

Plant tours were conducted which included observation of general plant / equipment conditions, fire protection and preventative measures, control of activities in

.'

progress, radiation protection controls, missile hazards, and plant housekeeping conditions / cleanliness.

1)

On April 15 and 16, the inspectors monitored activities related to preparations to remove the Unit I reactor head.

-

Communications between the involved groups was well established and job briefings were held with all of the involved personnel prior to the evolution.

In addition, switchyard controls were in place during these activities up until partial flood up above the reactor vessel flange was completed. The inspector concluded that management and personnel involved in the evolution addressed problems encountered in a quality manner, as opposed to being schedule driven. The inspectors also noted that the overall delays to the head lift evolution were problems with the checkout of the fuel transfer mechanism. These issues appeared to be repetitive equipment reliability / design issues continuing from previous refueling outages.

..

.

-

.

t

2)

On April 27 and 28, the inspectors monitored briefings, preparation, and actual core barrel removal from the Unit I reactor vessel. This evolution was well controlled with good management oversight and contingency actions in place.

Actual person-rem expenditure-for this projected high dose-job was 77 mr. This was well below the estimated dose of 300 mr.

This achievement was the result of detailed planning, mock-up training, effective shielding, and remote monitoring and was considered to be a strength.

3)

On April 16, the inspectors identified that a scaffold structure had recently been erected adjacent to the spent fuel pool (SFP) on elevation 734 of the auxiliary building.

The scaffold was estimated by the inspectors as approximately 25 feet high. The structure was secured for horizontal motion by two tie wires attached to the approximately three foot high exclusion barrier installed around the SFP. With the tie wires installed in this configuration, the inspectors concluded that the most probable place for the structure to fall, if disturbed, was into the SFP. The inspectors considered the erection of this structure as a potential safety hazard to the SFP and upcoming refueling evolutions and informed the control room.

The on-duty SOS reviewed the structure and agreed that the structure should be removed or restrained.

Subsequently, the licensee moved the refueling bridge adjacent to the scaffold until the structure was removed.

The inspectors noted that the scaffold was removed prior to the movement of any fuel assemblies in conjunction with Unit I refueling operations.

The inspectors reviewed the erection of the scaffolding with regard to SSP-7.55, CRITERIA FOR THE ERECTION OF SCAFFOLDS AND LADDERS INCLUDING THOSE IN SEISMICALLY _ QUALIFIED STRUCTURES, Revision I.

This SSP provides requirements for and criteria for the erection of scaffolds including those in seismically qualified structures. The inspectors considered that the licensee did not follow the requirements established by the SSP as follows:

-

Each 10 foot segment of the scaffold was not properly secured with two horizontal restraints on top of each segment.

-

Engineering did not review the as-constructed design as required when the above requirement was not or could not be met.

In addition, during review of the SSP, the inspectors considered that several aspects of the SSP did not provide clear guidance.

For example, the inspectors questioned why the Appendix B, FLOW DIAGRAM FOR ERECTION OF SCAFFOLDING did

..

.

t

.

!

not address evaluations for freestanding scaffolding. Other i

sections of the procedure required freestanding scaffold

evaluations if erection criteria could not be met. Also, the inspectors noted that the attachment points for the two provided restraints did not specifically meet the criteria specified in the SSP scaffold attachment points.

The inspectors discussed the above concerns with the licensee. The licensee _ agreed that the erection of the scaffold appeared to be in violation of the SSP.

The

,

inspectors considered that the root cause of the violation was inattention to detail and a lack of familiarity and training with respect to the requirements of the SSP. Of particular concern was that the modifications scaffold inspector did not recognize the potential problem and non-conformance with the requirements of the SSP. The licensee's proposed corrective actions included training and clarifications to the SSP with regard.to freestanding scaffold requirement.

In addition, the licensee also initiated a review of the approximate 650 scaffold installations to ensure compliance with the program. The inspectors considered that these corrective actions were appropriate. The failure to comply with the requirements of SSP-7.55 is a violation of TS 6.8.1 (327, 328/93-13-01).

This NRC identified violation is not being cited because criteria specified in Section VII.B of the NRC Enforcement Policy were satisfied.

c.

Biweekly Inspections The inspectors conducted biweekly inspections in the following areas: verification review and walkdown of safety-related tagouts

'

in effect; review of the sampling program (e.g., primary and secondary coolant samples, boric acid tank samples, plant liquid and gaseous samples); observation of control room shift turnover; i

review of implementation and use of the plant corrective action-

'

program; verification of selected portions of containment isolation lineups; and verification that notices to workers are posted as required by 10 CFR 19.

On April 21, during a tour of the Unit I lower containment, the inspector noted numerous ERCW piping which had a considerable amount of exterior corrosion. Most of the affected piping was i

less than 10 inch in diameter. The inspector noted this to system engineering management for review.

Subsequently, the inspectors were informed that this condition had been previously identified by the licensee in late 1992.

The inspector verified that a WR (C052934) had been properly established for the issue and noted that the correction of the problem was planned during the current

'

Unit I refueling outage. The licensee's proposed corrections i

included removal of the corrosion and coating of the piping. The j

k

.

o

.

inspectors will continue to monitor the licensee's actions to correct the problem during future inspections.

,

!

d.

Other Inspection Activities Inspection areas included the turbine building, diesel generator i

building, ERCW pumphouse, protected area yard, control room, Unit I containment, vital 6.9 KV shutdown board rooms, 480 V breaker and battery rooms, and auxiliary building areas including all i

accessible safety-related pump and heat exchanger rooms.

RWPs were reviewed, and specific work activities were monitored to assure they were being accomplished per the RWPs.

Selected radiation protection instruments were periodically checked, and equipment operability and calibration frequencies were verified.

e.

Physical Security Program Inspections In the course of the monthly activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital area access controls; searching of personnel and packages;

,

escorting of visitors; badge issuance and retrieval; and patrols

-

and compensatory posts.

In addition, the inspectors observed protected area lighting, and protected and vital areas barrier integrity.

f.

Licensee NRC Notifications

.

On April 30, 1993 the licensee made a notification to the NRC as required by 10 CFR 50.72 with regard to low temperature overpressure protection setpoints being non-conservative. The potential problem was identified by Westinghouse to TVA in a letter dated March 15, 1993. TVA's evaluation, which was documented in an engineering evaluation dated April 30, 1993 concluded that Unit 2 operation in MODE 5 was bounded.by current setpoints as long as the RCS temperature was maintained above 120 degrees F.

Unit I was defueled and was not currently affected by the problem. However, before the vessel head had been removed for refueling, non-conservative setpoints did result in operation outside of technical specification limits. The licensee will submit an LER for this event.

g.

Outage Functional Area Reviews During this period, the inspectors focused on review of licensee performance during the beginning of the Unit 1 Cycle 6 refueling outage, as well as the Unit 2 forced outage in several functional areas. The following conclusions were reached during this period:

Operations - Operator performance during this period was considered to be mixed.

Several evolutions were observed in which

-

.

- -

.

operator performance was good. They included significant tagouts of safety systems during the two unit outages and control of

-

activities during the Unit-1 core barrel lift. However, other evolutions were noted, including the Unit 1 RCS draindown which indicated a lack of full control of ongoing evolutions.

-

Radiological Controls - Performance in this area was considered to

be very good.

Person-rem expenditure and personnel contaminations were well below projected levels even though RWP work experienced substantial growth due to both units being in outage.

A significant accomplishment was the removal of the Unit 1 core barrel with an expenditure of 77 mr. The inspectors also noted, during Unit I containment tours, several enhancements in the

'7 radiological controls area.

These enhancements included hot

'

washing capability to help in containment decontamination, automatic closure devices for vacuum cleaner suction inlets, and improved staging installation to help personnel movement through containment.

However, an event did occur during the inspection

,

period which involved a contaminated individual leaving the site This event will be reviewed during future inspections.

+

area.

!

Maintenance - Performance in this area appeared to be satisfactory. During the period, significant work was being identified and loaded into the schedules of both units to support hardware corrective actions for restart based on a licensee

_'

identified list of restart requirements.

Engineering / Technical Support - Performance in this area was mixed.

Performance by some engineering personnel including system

.

engineers and design engineers in support of identified restart

,

i activities was good. However, in specific areas reviewed, including temporary RCS level instrumentation design and the initial Unit I reactor cavity leakage evaluation, engineering

,

support could have been better to insure system reliability and

,

enhance safety.

Safety Assessment / Quality Verification - Performance in this area was considered to be improving.

The licensee had established a

senior management group to review plant issues for restart. This

group appeared to be making conservative restart decisions.

i Within the areas inspected, one non-cited violation was identified.

4.

Maintenance Inspections (62703 & 42700)

During the reporting period, the inspectors reviewed maintenance activities to assure compliance with the appropriate procedures and j

i l

-

._

.

r requirements.

Inspection areas included the following:

!

a.

Temporary Services Through Containment Penetrations

,

Inspection continued with regard to maintenance activities associated with installation of temporary services through

,

containment penetrations, and temporarily foaming of the

!

penetration openings with the services installed. This activity was addressed in paragraph 4.a of inspection report 327, 328/93-i 09.

In that report the inspectors stated that at the end of the

'

period they were reviewing the requirements of TS LC0 3.9.4 with NRR. The specific discussion dealt with whether the licensee's process of temporarily foaming containment penetrations with temporary services installed through them met the requirements of the TS.

On April 9, 1993 the inspectors discussed the issue with NRR and were informed that the foaming process for sealing of containment penetrations through which temporary services are installed to

'

support outage activities did currently satisfy the requirements-

of TS LC0 3.9.4.

Therefore the licensee's current approach for

installation of temporary services with foam seals meets the requirements of TS.

This position was based on containment integrity requirements for a fuel handling accident only. The NRC is currently reviewing this area in the context of shutdown risk scenarios and may be providing additional guidance in the future.

,

The inspectors then reviewed the foaming process with regard to procedural requirements. Specifically, the inspectors wanted to determine the type of seal that would be provided for cables which were grouped together in a configuration observed through-

'

penetration X-117. On April 9, 1993 licensee engineering and craft personnel conducted a foaming demonstration for the inspectors. This demonstration provided practical insight into the foam application process. Several cables were grouped together, similar to the grouping through penetration X-ll7. The foam was mixed and applied in a container representative of the penetration in the same manner that it was applied in containment penetrations. The fluid quality of the foam at initial injection

'

allowed for penetration around each cable, even though the cables were grouped together. After the foam had cured, the test container was cut open, and the foam plug was dissected to observe the sealing for the cables. The inspectors noted that each cable in the group was sealed in a honeycomb manner by the cured foam.

Based on this demonstration, the inspectors consider that the process used to install and seal cables through containment penetrations with foam meets the procedural and technical requirements for containment integrity which is presently required for MODE 6 core alterations.

.l

h

.

-

.

-

- -

-

,

>

.

I

b.

CCS Surge Tank Level Control i

Inspections continued with regard to problems associated with the Unit 2 CCS surge tank automatic makeup level control valve 2-LCV-

70-63. This activity was previously reviewed in paragraph 4.b of

.

Inspection Report 327, 328/93-09.

,

Chronoloav of Licensee Actions

On March 8, 1993, anomalous CR board indications for the surge

.

tank automatic makeup level control valve were identified. _

!

Operators took the handswitch out of automatic and placed it in

'

,

the closed position.

This action was taken because of the apparent failure of the surge tank level controls to function properly, and was appropriate. An Abnormal System Status File Sheet was prepared to document the makeup valve being in the off-normal position while troubleshooting was accomplished. Operators l

initiated WR C174431 to troubleshoot the problem.

!

Troubleshooting identified that a wiring discrepancy existed such

!

that the surge tank low level switch was jumpered out of the circuitry that controlled the operation of the valve. This

resulted in a demand signal for a low level condition always being

in and level essentially being controlled only by the high level setpoint. Operations was notified, and the equipment was left in

the as-found (incorrect) condition. The WR was held open.

<

On March 10, Drawing Deficiency 93DD6572 was initiated. The DD

,

identified the problem as a discrepancy between the termination

and schematic drawings, and documented that the wiring in the

plant was incorrect.

Pending evaluation of the drawing discrepancy through the DD process, the makeup valve handswitch remained in the manual closed position.

'

During the first week of April, repair of the hardware was completed under WR C174431, and the handswitch was returned to automatic. The other related handswitch was reviewed for proper configuration and no additional problems were identified.

The

,

date and circumstances of the occurrence of the wiring

,

discrepancy, and why the problem was not noticed sooner by the.

'

operators, had not been determined by the licensee as of the end of the inspection period.

The licensee issued two Problem Evaluation Reports to address this issue.

SQPER930096 was initiated on April 5, 1993, to address the

-

makeup valve not being in automatic in accordance with procedure 2-S0-70-1.

This PER was superseded by SQPER930103, which was initiated on April 6, 1993, and questioned whether the condition

met the intent of the DD process. The second PER was open at the j

end of the inspection period.

'

i

.

--- -

..

.

'

i FSAR Review of Makeuo Valve Issue The inspectors raised several questions, documented in IR 327,328/93-09, which the licensee reviewed in conjunction with their own investigation into the issue. In particular, the inspectors questioned whether the FSAR had been properly considered when reviews were performed to support operation with

!

the makeup valve in manual and closed.

.

10 CFR 50.59 allows the licensee to make changes to the plant as described in the FSAR provided the change does not constitute an

.

l unreviewed safety question.

Changes to the facility must be

.

reviewed to ensure that an unreviewed safety question does not

'

result. Because the Sequoyah FSAR requires automatic makeup capability for the'CCS surge tank, operation with the makeup valve out of automatic was a change to the. plant configuration as described in the FSAR.

As documented in IR 327,328/92-31, in October 1992 the inspectors had brought the need to consider FSAR requirements for automatic CCS makeup capability to the attention of the licensee with respect to previous instances of operation with the handswitch in manual.

During this inspection period, NRC review found no documentation that the FSAR had been reviewed or considered with respect to the licensee's decision to operate with the valve control switch in manual rather than in automatic. On April 5, a 10 CFR 50.59 evaluation was completed and was attached to the DD package.

However, the subject of the evaluation was the correction of the drawing and the return of the level instrumentation to the normal FSAR configuration of automatic operation. The change to the method of operating CCS surge tank makeup was not reviewed against the FSAR.

,

Although it was not evident that the licensee had consciously

';

considered FSAR requirements with respect to automatic makeup capability, in this case, the unit was in Mode 5 and CCS was not

required by TS to be operable.

The applicable sections of the FSAR require the CCS to be functional in that mode, as opposed to TS-operable. With the handswitch in the manual closed position, the surge tank was functional even though makeup was not automatically provided. Therefore there was no direct safety significance to having the handswitch in manual, rather than automatic.

Prooram Reouirements for FSAR Review of Nonconformances Although placing the surge tank level handswitch in manual was not safety significant, inspectior, of the issue raised potential

-

programmatic concerns. There appeared to be differences in the general understanding of licensee managers and operations personnel concerning when plant configuration changes must be i

evaluated against the requirements of 10 CFR 50.59. At least one

____

.

,

individual stated that 10 CFR 50.59 need only be considered when a I

configuration change renders the SSC inoperable. Other personnel stated that 10 CFR 50.59 did not need to be considered if the configuration change was associated with, though not strictly part of, a maintenance activity.

l When the mis-wired level switch was identified, the licensee made l

a conscious decision to delay fixing plant hardware while a DD was i

processed.

In additicn, a conscious decision was made to continue j

operation by placing the handswitch in manual. The inspector

,

reviewed relevant licensee procedures to determine program

'

requirements applicable to situations such as this. The following

,

documents were reviewed:

-

Sequoyah FSAR

-

SSP-2.11, DRAWING DEVIATIONS, Revision 3

-

SSP-3.4, CORRECTIVE ACTION, Revision 7

-

SSP-6.25, MAINTENANCE MANAGEMENT SYSTEM, PERFORMANCE OF WORK ORDERS, Revision 2

-

SSP-3.6, PROBLEM EVALUATION REPORTS, Revision 3

-

SSP-12.2, SYSTEM AND EQUIPMENT STATUS CONTROL, Revision 3

-

SSP-12.ll, CONTROL AND TRACKING OF COMPENSATORY MEASURES, Revision 0

-

SSP-12.13, 10 CFR 50.59 EVALUATION OF CHANGES, TESTS, AND EXPERIMENTS, Revision 3

-

SSP-12.14, JUSTIFICATION FOR CONTINUED OPERATION / WAIVERS OF COMPLIANCE, Revision 0 Procedure SSP-12.13 documents requirements and procedures for reviewing plant changes against the requirements of 10 CFR 50.59.

" Changes in the facility as described in the FSAR" are defined as changes which may alter the design, function, or method of performing the function of a SSC (either safety-related or non safety-related) described in the FSAR.

Per SSP-12.13, a Safety Assessment (SA) is a written determination of whether the facility change is safe and if a TS change or SE is required. A Safety Evaluation (SE), is a written technical evaluation that provides the basis for the determination that the change does not involve an unreviewed safety question (USQ). An SE is required if the function of a component described in the FSAR is altered, or if the nonconformance alters the method of performing the function of a larger SSC described in the FSAR.

For systems or components that are taken credit for in the SQN

-

__.

'

.

t

t i

safety analysis and for which allowed outage times are not i

specified in the Technical Specifications, an SE shall be written.

'

The inspector reviewed the sections of SSP-12.13 which pertain to changes to the plant associated with maintenance activities, and the guidance on distinguishing between plant changes and maintenance. According to Appendix B of SSP-12.13, an important

consideration of the SA is to distinguish changes from maintenance

'

activities.

Maintenance _ activities are required to be reviewed under 10 CFR 50.59 if they place the plant in a condition where it

functions differently than described in the FSAR. Appendix B of SSP-12.13 further states that changing plant configurations while i

work is in progress may involve an unreviewed safety question, and

temporary changes to the facility while work is in progress should

'

be evaluated to determine if an unreviewed safety question exists.

,

Deleting an automatic or manual feature of SSC is discussed in l

SSP-12.13.

SSP-12.13 also addresses when the SA is to be used for a plant /FSAR discrepancy as identified and reported on a

corrective action document.

l The inspector also reviewed the above procedures to identify the existing guidance on when SSP-12.13 should be invoked, and what

!

activities require a SA. 10 CFR 50.59 reviews may be triggered in

-

several ways when the plant configuration is changed. When a

!

change is made to the plant configuration, procedure SSP-12.2

-

requires that an SA/SE in accordance with SSP-12.13 shall be

,

performed if necessary.

The Abnormal System Status File Sheet has

-

a block for documenting whether an SA/SE is required.

,

The inspector determined that the licensee's Corrective Action

Program procedures clearly require conditions adverse to quality to be promptly reviewed for effects on operability.

Procedural guidance for determining and formally documenting the operability

of safety-related equipment (both TS and non-TS) is found in SSP-12.14. Section 3.2.1 of this procedure states that the full scope of the design bases, including TS and the FSAR, shall be examined

'

in determining operability. Therefore, the operability review given to any nonconforming condition should include a review of

!

,

FSAR requirements.

According to SSP-12.14, if the conclusion of the operability determination is that the safety-related SSC is inoperable, then a

JC0 is required for continued plant operation. Section 3.3.1 requires a documented engineering justification if equipment (either TS and non-TS) is determined to be operable, but will

remain in a nonconforming condition for an extended interim period i

of time pending corrective action. The procedure requires that,

)

if appropriate, based on safety significance, a 10 CFR 10.59 review in accordance with SSP-12.13 shall be performed to justify i

the extended operating time. Appendix A of SSP-12.14 states that delay or partial correction of a condition adverse to quality is

- - - - - - - - - - - - - _

,

.

considered a change in the facility and subject to 10 CFR 50.59 review.

For the specific case in question, the first occasion to possibly require or trigger an FSAR review was the entry of the off-normal handswitch position into the system status log.

The Abnormal

System Status File Sheet written to configure the valve in the i

off-normal closed position was, in fact, marked to indicate that an SA/SE per SSP-12.13 was required. However, the ASOS then i

marked the SOS /SR0 signature "N/A", which is only allowable if an l

'

SA/SE is not required. When this was questioned by the inspector, some licensee personnel stated the SA/SE should have been i

performed.

Other individuals stated that the requirement for an SA/SE was checked in error on the Status file Sheet because it was anticipated that the equipment would be quickly repaired and the system restored to the automatic configuration.

The inspectors observed that this reasoning was made apparently without the operators' recognition that the FSAR was applicable.

The inspectors noted that SSP-12.11 requires programmatic controls of measures taken to compensate for defeated or degraded safety functions. Although the effect on plant operations of placing the surge tank makeup in the non-automatic position was minimal, the aggregate effect of a significant number of such minor compensatory measures, if not properly controlled, could hamper the ability of the operators to perform under transient or accident conditions.

Corrective Action Procedure Review The inspectors reviewed the applicable CAP procedures which might require review or trigger consideration of FSAR requirements.

In the specific case of the surge tank makeup valve, the wiring discrepancy was identified during the performance of a work request, which is an established part of the CAP.

SSP-6.25 states that if discrepancies between the plant configuration and an as-constructed drawing are identified while performing a WR, they are to be handled through SSP-2.11, and/or SSP-3.4, and/or SSP-3.6. If the WO is determined to potentially affect operability, then a SCAR (SSP-3.4) or PER (SSP-3.6) must be initiated.

The licensee elected to handle the wiring discrepancy through the DD process (SSP-2.11), and indicated to the inspector that this was in accordance with their established corrective action program. The inspector confirmed through a review of SSP-2.11 that the procedure is intended to address differences between the as-found plant configuration and the applicable as-constructed drawings, including those cases where the hardware is known to be incorrect. The intent is to ensure that the drawings are correct and then to perform the repairs via a WR in accordance with correct drawings.

_ - _

_ _

.

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _

,

o

.

Discussions with the licensee indicated a lack of consensus among management and other personnel as to whether a PER (SSP-3.6)

should have been used to address the miswired makeup switch rather than a DD (SSP-2.ll).

Handling this particular issue through the DD process delayed correction of the known hardware deficiency while the drawings received engineering review.

The inspector reviewed SSP-3.6 and SSP-2.11 to determine the differences, if any, between the level of review given to nonconforming items, and the timeframes for these reviews. The inspector determined that both procedures require determination of whether the nonconforming condition affects operability. However, the relevant differences between the procedures are:

(1)

SSP-3.6 requires the initiator to "promptly" report the adverse condition, and immediately carry the PER form to

_

his/her responsible supervisor.

-

SSP-2.11 allows two working days for the initiator to submit either a DD or another corrective action document. After initiation, both SSP-3.6 and SSP-2.11 allow three days for supervisory review.

(2)

SSP-3.6 requires the responsible supervisor to "promptly" perform a review for potential effects on operability, and immediately handcarry conditions "potentially" affecting operability to operations management for an operability determination. Section 3.2.11 requires the operability determination to be made within three days.

SSP-2.11 indicates that the operability determination is to I

be made after the supervisory review ha:, been completed (up to five days after discovery of the condition).

(3)

SSP-3.6, Section 3.2.11, requires the operability determination for potentially reportable items to be made by

the Operations Manager or the Duty Plant Manager.

SSP-2.11, Section 3.2, states that operability determinations are to be performed by the STA or ASOS. SSP-12.2 also specified that operability determinations be made by the AS0S. The inspector noted that these procedures appeared to conflict with SSP-12.14, Section 3.1, which states that the 505 is responsible for determining TS operability.

(4)

SSP-3.6 invokes SSP-12.14 directly, whereas SSP-2.11 does not.

SSP-2.ll requires that nonconforming conditions documented on DDs shall be reviewed for " Technical Specification Operability". There is no specific mention of reviewing the condition against the FSAR. Although the wording of SSP-12.14 indicates that it is applicable

. _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _.

_ _ _ _

_ _ _ _ _

. _ _ -. _ _ - _ _ _ _ _ _ _

-

,

.

whenever determinations of operability are made, it is not referenced in SSP-2.11.

(5)

Following the three days allowed for supervisory review, SSP-3.6 allows twenty working days for the responsible organization to develop and approve corrective action for a PER, although extensions may be granted. As applicable, a technical justification must be obtained from Site Engineering or Nuclear Fuels.

SSP-2.ll allows the Technical Support Section fifteen working days for determining the required disposition for a DD.

Because both procedures require reviews for operability, the inspector concluded that either the DD or PER process can be used for handling situations such as this, provided the specified

timeframes are followed, the requirements of SSP-12.14 and SSP-12.13 are applied, and the FSAR is considered in the review process.

Time frames for initiating corrective action were comparable. Both processes could lead to the correction of the

nonconforming condition through a WR. However, DDs receive a lower

level of review for operability (AS0S vs. Operations Management),

and operability reviews for DDs are not required to be performed as quickly as for PERs (up to five days for DDs vs. "promptly" I

handcarried for PERs).

A review of documentation associated with the licensee resolution of the CCS surge tank makeup issue revealed discrepancies which possibly indicate a lack of uniform understanding of operability determinations per SSP-12.14.

For example, the nonconforming condition was classified as not affecting operability on the status file sheet, and on SQPER930096 as not potentially affecting operability.

However, the condition was classified on SQPER930103 as potentially affecting operability, and on 93DD6572 as affecting operability.

No followup operability evaluations or other documented actions were evident with regards to SQPER930103 or 93D0657?..

In addition, the inspector noted that it was not totally clear from the closure package for 93DD6572 that the hardware problem had been corrected through the WR, although it had. SSP-2.ll requires that a WR generated to correct the Plant Configuration be referenced in the Problem Solution section. This was not done, although the WR number was noted elsewhere on the form.

Conclusions Overall, the inspectors considered that the licensee's actions to correct the specific wiring problem with surge tank makeup valve logic were adequately accomplished. However, the inspectors also concluded that operations personnel were not consistently and routinely considering the FSAR when reviewing abnormal configurations and equipment problems.

In addition, the

_ _ _ _

__

. _ _ _ _

.__

^

.

..

.

inspectors considered that the process was complex, and the multiple administrative procedures posed some confusion as to when they should be applied.

The inspectors expressed these concerns to the licensee. At the end of the inspection period, the licensee was evaluating the issues and relevant administrative processes, c.

Refueling Cavity Leakage r

On April 19, during fuel movement activities, the inspectors became aware of apparent leakage from the refueling cavity collecting in the Unit I containment (keyway) sump. This leakage was initially estimated at approximately 4.5 gpm and was observed with the cavity water level at approximately elevation 726 (refueling level). The potential sources of the leakage,.as.

identified by the licensee, were the refueling cavity liner, hot-and cold leg nozzle dams, seals installed in the normally open

penetrations between upper and lower containment (located in the bottom of the refueling cavity), and the reactor cavity seal ring i

around the vessel.

'

On April 21, the inspectors toured the Unit I lower containment-to determine the extent and most significant source of the leakage.

>

All of the proposed leakage paths exhibited some evidence of leakage, with the exception of the reactor cavity seal.

Leakage

'

past the reactor cavity seal could not be verified due to inability to access this area due to radiological concerns.

The inspectors reviewed the design of. the reactor cavity seal arrangement. A passive one-piece design is used, composed of an inflatable bladder with a wedge and four-inch wide T-section at

,

the top. The seal is placed into the two-inch opening between the

,

'

vessel flange and the cavity liner, and manually compressed.

The

>

compression of the wedge shaped portion of the seal-into the annulus opening and the inflation of the bladder keep'the seal in place, and provide good sealing characteristics.

Bladder pressure is maintained with service air, with a bottled air supply as backup. The licensee is currently considering going to a segmented seal design.

The inspectors reviewed current licensee compliance with relevant commitments resulting from NRC Bulletin 84-03, Refueling Cavity Water Seal. The bulletin was issued as a result of the August 1984 cavity seal failure at the Haddam Neck nuclear plant, during which water level decreased to flange level within 20 minutes. The following documents were reviewed:

-

Sequoyah FSAR

-

NRC Bulletin No. 84-03: Refueling Cavity Water Seal, August 24, 1984

_ _ _

.

..

.

L

-

TVA Response to Bulletin, dated October 2, 1984

-

TVA Letter to NRC, Sequoyah Nuclear Plant Units 1 and 2 -

Bulletin No. 84-03:

Refueling Cavity Water Seal, October 17, 1984

-

TVA Supplemental Response to Bulletin, dated October 26, 1984

-

NRC Letter to TVA, Meeting Summary: Bulletin 84-03 Refueling Cavity Water Seal, March 14, 1985 i

l i

-

TVA Letter to NRC, dated June 12, 1985, Response to NRC Letter of March 14, 1985

-

NRC IR 327,328/85-31, dated October 21, 1985

-

TVA Memorandum, Burzynski to Gridley, Sequoyah Nuclear Plant (SQN) Units 1 and 2 - Exit Meeting Minutes for Snubbers, Masonry Block Walls, and Pipe Support Thermal Expansion -

l Inspection Report ((IR) 89-04.

l

-

NRC IR 50-327,328/89-04, issued February 18, 1989.

-

A01-29, Dropped or Damaged Fuel Assembly or Loss of Reactor Cavity Water Level, Revision 9 i

-

0-SI-0PS-000-065.S, Revision 4, Refueling Surveillance Log l

-

FHI-6, Preparation for Refueling, Revision 34 i

Results of the inspector's review were as follows:

t

-

Technical issues associated with the adequacy of the

,

Sequoyah seal design were adequately resolved, and the

!

Bulletin was closed in IR 327,328/85-31. The Sequoyah seal design was significantly different than that of Haddam Neck, and TVA demonstrated that a gross seal failure like that at Haddum Neck is not a creditable event at Sequoyah. The pneumatic design precludes the possibility of any significant displacement, and if the seal were to deflate,

,

it would not be forced through the annulus. The more likely accident scenario would be for seal deflation to create a 1/16 inch gap between the seal and the flange. The maximum leak rate for this failure mode was predicted to be about 3200 gpm. The RHR system could provide makeup capability for l

a sufficient length of time to allow all fuel assemblies in

~

transit to be placed under water.

-

TVA's letter of October 17, 1984, stated that water level would be monitored once per shift. The inspector determined that SI-65 includes a reactor cavity seal check, with

_

_____-__________--__-___ - _ _

_-

-

_ _ _ _ - -

__

_ _ - _ _ _ - _ _ _ _ - _ _ _

_

3 :.

y m

u

verification of water _ level above the flange. A closed -

circuit camera wasl put in use to monitor sump. level. -

However, the inspectors noted that the panning feature off

~ '

the camera was subsequently disabled by the licensee so that.

the sump level indication was always on screen. Although-sump level could still be monitored, this decreased their

,'

capability to diagnose the-source of leaks into the sump.

-

The licensee response of October 26, 1984, stated that-A01s had been revised to assist the reactor. operator in diagnosing the symptoms of a potential reactor cavity seal leakage during refueling, and.to prescribe the corrective actions needed to mitigate such an event. The inspector._

reviewed A01-29, and verified that it contained adequate j

measures for diagnosing and mitigating a seal failure.

l

-

In NRC 327,328/89-04, the inspector expressed concern <that plant procedures did not require periodic surveillance of-the backup air supply to the seal to ensure the system is operable. During this inspection period, the inspector confirmed that surveillance of the' backup air supply was a

required by. SI-65 and was being performed once per shift.

-

The licensee response of October 26, 1984, stated that visual inspection and durometer readings of the seal would be required prior to use, to ensure it had not degraded during storage. The inspectors confirmed through' discussions with the systems engineers that this inspection had been performed.

t The inspector concluded that the licensee had taken adequate measures in response to Bulletin-84-03.

With regards to the current identification of sump inleakage, the inspectors questioned the licensee-with regard to assurances that the reactor cavity seal was not degraded. As a result of the:

discussions with the licensee, the inspectors concluded that the-licensee could not positively ascertain that no leakage was from the cavity seal. The licensee stated.that the collection of water (

in the keyway sump, was at approximately 4.5 gpm and the sump-pump, with a flow rate of 6 gpm, could adequately handle the

-

inleakage.

In addition, the licensee stated that.the evidence

which was used to establish the 4.5 gpm sump inleakage, may have, been questionable and inconsistent. The inspectors also were made aware that some leakage was also observed during. previous-refueling outages.

Prior troubleshooting of this previous identification of the problem, which included penetrant testing, did not identify any leakage points through the cavity liner.

The inspectors continued to monitor the cavity leakage up to and during evolutions to remove the reactor vessel core barrel for inspection. This evolution, performed April 26 and 27, ' required

__ _ _ -

___-_-_ -___ _ -__

_ _ - - - - -

.

t the cavity be flooded to elevation 726 for radiation shielding during the lift.

The inspectors expressed concerns to the licensee prior to the evolution with regard to the actual reactor cavity seal leakage and assurance that the reactor cavity seal was not degraded. The inspectors concluded that the licensee was monitoring the reactor cavity leakage. However, they did not fully understand the quantity and sources of the leakage.

Subsequent to these discussions, the licensee took a more aggressive approach to understanding the-cavity leakage.

The inspectors were informed that the original sump in-leakage values were not correct because the evaluations did not take into account the slope of the sump floor. After the floodup for the core barrel removal, the licensee reevaluated the leakage prior to the

,

evolution. The results indicated that inleakage to the cavity was approximately 1.6 gpm. The licensee concluded that this leakage was acceptable, and decided to proceed with the barrel evolution.

'

The inspectors noted that the licensee also modified contingency measures to improve the means of water addition to the cavity in the event of a problem, prior to the evolution. After the core barrel removal, the cavity leakage was again reevaluated.

The results indicated that the leakage had increased to approximately 2.5 gpm. The inspectors discussed this increase with the licensee. The licensee postulated that an increase in leakage supported a hypotheses that the cavity leakage was primarily due to possible cavity floor liner seam leakage.

The licensee postulated that when the core barrel (weighing approximately 300,000 pounds) was placed on the cavity floor, the leakage increased due to the increased stress place on the liner joints.

The licensee intends to continue to evaluate the cavity leakage and develop a means to identify and correct the potential leakage points.

The inspectors concluded that, prior to filling the cavity for the core barrel removal, the licensee was recording sump in-leakage but was not aggressive in evaluation of the leakage and identification of operational cautions for refueling evolutions.

Increased sensitivity to reactor cavity leakage was evident during subsequent core barrel removal evolutions.

The inspectors noted that an II was initiated to continue to develop long term corrective actions for the cavity leakage problem.

d.

Ice Condenser Activities During the inspection period, the inspectors monitored activities associated with maintenance of both of the unit's ice condensers.

Significant activities were ongoing or planned for the Unit 1 ice condenser during the refueling outage. These included attempting to weigh all of the accessible ice baskets in the condenser.

By the end of the inspection period, the licensee had weighed approximately 1250 baskets; however, approximately 700 of the remaining baskets were frozen or otherwise unable to be moved.

i

_.

_ _ - _ _

..~

.

Dependent on the difficulty of dislodging the frozen baskets, the licensee expects to free approximately 140 additional baskets for baseline weighing during the outage. The licensee intends on servicing (adding ice) to all baskets in high sublimation zones, unless baskets weigh greater than 1300 pounds.

Servicing will also include all frozen baskets suspected to be below 1300 pounds.

The inspectors will monitor the servicing of the Unit I condenser during subsequent-inspection activities.

The attempt to base line the as-found ice weights in the Unit 1

!

ice condenser was partially in response to previous concerns identified in October of 1992 and discussed in Inspection Report 327,328/92-31. This report specifically questioned the "as left condition of the condensers after servicing.

Safety Evaluation Report No.131 to the Unit 1 TS allowed revisions to portions of TS surveillance requirement 4.6.5.1 which included reducing the required basket weights from 1200 pounds to 1155 pounds. However, the SER also stated that " operability of the ice beds in the ice condenser requires that the ice inventory be evenly distributed throughout the ice condenser bays throughout the operating cycle."

Based on these statements, the licensee was taking efforts to better understand the as-left and as-found ice weight and was planning on servicing those baskets which required additional ice mass based on the initial weighing.

In addition, the licensee was planning to visually inspect the ice condenser from the bottom of the baskets for indications of ice voids which would warrant further servicing. The inspectors concluded that the licensee was taking appropriate actions to establish initial baseline trending data for the Unit 1 ice condenser.

Due to the forced outage on Unit 2, the licensee reviewed whether the ice mass in the Unit 2 ice condenser would contain the required amount to complete the current fuel cycle.

Based on statistical data from previous outages and the "as found" weight of approximately 34 baskets, the licensee determined that the row 1, group 3 baskets may complete the cycle with less that the l

required amount of ice weight. This particular row / group had been l

previously identified as the area of the condenser which has the most sublimation.

Of the 15 baskets weighed in this row / group, the licensee indicated that the "as found" weights ranged from approximately 600 - 1500 pounds.

Based on this information, the licensee decided to service the 72 baskets in row I group 3 and reweigh a sample of these to assure the addition of the nccessary amount of ice per basket. The licensee indicated that with this additional ice servicing, operability of the ice condenser was assured through the remaining fuel cycle for Unit 2.

On April 20, the inspectors toured the Unit 2 ice condenser from both the top and bottom of the ice baskets.

The inspectors noted significant sublimation in the row 1 baskets, particularly group 3.

The licensee had predicted these baskets as worst case.

However, the inspectors also noted that portions of other (non-row

_ _ _ _ _ _ _ _ _ _ - _ _ _ -

- -

.

~..

..

.- _

.

..'

t

f

1) ice baskets had also sublimated, in various degrees, such that the inspectors. questioned whether some individual baskets could meet the TS surveillance required weight amount. The inspectors observations were limited to approximately 10 feet of viewing

distance from the bottom of the condenser.

Baskets observed from i

the top of the condenser appeared to be less affected by ice l

sublimation. The inspectors discussed these observations with the

licensee, and asked whether these indications warranted additional

'

weighing. The licensee indicated that, based on the TS required (

surveillance performed during the last Unit 2 refueling outage in l

May of 1992, the ice mass in the condenser, as a whole, was.

acceptable. The inspectors concluded, at the end of the period, that the licensee had not fully utilized the opportunity of.the

,

Unit 2 forced outage to service some ice baskets which appeared, l

through visual inspection, to be'near or below TS surveillance

minimum ice weight values. However, due to additional scheduling l

reviews, the licensee is evaluating whether to conduct the TS surveillance requirement to demonstrate long term ice condenser

operability prior to. Unit 2 restart.

The inspectors will continue to monitor activities in these areas

!

on both units during resolution of URI-327, 328/92-31-01, Concerns-

Regarding Determination of requirement of TS 4.6.5.1 During e

Performance for "As Found" Ice Condenser Status.

j Within the areas inspected, no violations were identified.

!

5.

Surveillance Inspections (61725 & 42700)

,

During the reporting period, the inspectors reviewed various.

I surveillance activities to assure compliance with the appropriate

.

procedures and requirements.

The inspection included a review of i

selected procedures and observation of surveillances.

'

During the later part of the period, the inspectors reviewed activities

associated with calibration of-the Unit 1 RVLIS. This review was done,-

!

in part, to determine why RVLIS was not available for use during-RCS i

draindown on April 9, 1993 (see paragraph 3.a).

The inspectors obtained

'

a copy of completet surveillance instruction 1-SI-ICC-068-003.0, OFFLINE CHANNEL CALIBRATION OF REACTOR VESSEL' LEVEL INSTRUMENTATION SYSTEM AND

RCS WIDE RANGE PRESSURE TRANSMITTERS TRAINS A & B, Revision 0..

The.

i inspectors determined ~ that the calibration was performed over a period

!

from March 17, 1993 to beyond the end of the current inspection period.

l The inspectors questioned the licensee as-to why RVLIS was not scheduled i

to be available during RCS draining. The licensee stated that they did

_

not intend to use RVLIS as a means of RCS level indication-during

'j draining evolutions. The inspectors consider'that the licensee's

.

decision to not have RVLIS available for RCS draining demonstrated.a low j

safety sensitivity to this important operational evolution.

,i a

Within the areas inspected, no violations were identified.

i

.!

I

.

-

- _.

-

., -

- -

. -

-.

.

<

.-

.

i

l

,

6.

Evaluation of Licensee Self-Assessment Capability (40500)

l During this inspection period, selected reviews were conducted of the licensee's ongoing self-assessment programs in order to evaluate the effectiveness of these programs.

On April 22, the inspectors monitored portions of a special NSRB meeting j

which was convened to review Sequoyah's plans to address current plant problems and to establish permanent recurrence controls.

Site management briefed the NSRB on the scope of the corrective action plans

.

in the areas of B0P, technical programs, Operations, backlog, personnel performance, independent assessments, quality assurance assessments, and i

corporate support. The inspectors concluded that the meeting provided a good overview of the licensee problem areas.

Within the areas inspected, no violations were identified.

7.

Licensee Event Report Review (92700)

The inspectors reviewed the LERs listed below to ascertain whether NRC l'

reporting requirements were being met and to evaluate initial adequacy of the corrective actions. The inspector's review also included

>

followup on implementation of corrective action and/or review of licensee documentation that all required corrective action (s) were either complete or identified in the licensee's program for tracking of

outstanding actions.

i a.

(Closed) LER 327/92-27, Reactor Trips as a Result of a Switchyhrd Power Circuit Failure Fault and a Unit 2 Entry into Limiting Condition for Operation (LCO) 3.0.3 When Both Centrifugal Charging Pumps Were Removed Fror

'.

The issue involved a dual unit reactor / turbine trip frs app. ximately 100% power on December 31, 1992.

The NRC's review i f this avent was documented in Inspection

,

Report No. 50-327, 328/93-cl.

...... cement action resulted from

!

this inspection activity.

Corrective actions for this LER will be

'

reviewed as part cf the closecut of the enforcement action.

b.

(Closed) LER 328/92-12, Manual Auxiliary feedwater Start as a

'

Result of a Secondary System Perturbation. The issue involved a fire at the B-phase main transformer neutral bushing. An emergency shutdown of the reactor was initiated utilizing Abnornal Operating Instructions.

With the reactor at 8% power, the

'

isolation valves on all three strings of intermediate pressure condensate heaters automatically began to close as a result of high-high heater levels. Operations personnel recognized that j

suction would be lost to the operating main feedwater pump,

manually started all auxiliary feedwater pumps, and tripped the

.

operating main feedwater pump. The plant was subsequently placed i

in a stable condition.

The inspectors reviewed the licensee's actions and consider them to have been appropriate.

l

>

!

.,.

.

c.

(Closed) LER 328/92-13, Improper Performance of a Surveillance Requirement for Functional Testing of Circuit Breakers. The issue involved a determination that the wrong breaker had been tested

'

during an SI performance and was discussed in NRC Inspection Report No. 50-327, 328/92-30.

Corrective actions were reviewed by the inspectors and were considered adequate.

d.

(Closed) LER 328/92-15, Manual Auxiliary Feedwater Start as a Result of a Secondary System Perturbation. The issue involved the manual start of the MDAFW pumps during a turbine runback event that occurred on Unit 2 on December 8, 1992. Auxiliary feedwater was manually started as a result of low steam generator level and a steam flow /feedwater flow mismatch, following a condensate feedwater transient. The transient was a result of a failure of the No. 3 HDT level controller relay cleanout plug, which did not operate as designed. This issue was addressed in detail in Inspection Report 327, 328/93-02.

,

e.

(Closed) LER 328/92-16, Refueling Water Storage Tank (RWST)

Temperature Below lechnical Specification (TS) Requirements. The issue involved an event that occurred on December 24, 1992, in which the Unit 2 RWST temperature was below the TS minimum requirement of 60 degrees F.

This issue was discussed in NRC Inspection Report No. 50-327, 328/92-38.

Enforcement action

'

resulted from this inspection activity.

Corrective actions for this LER will be reviewed as part of the closeout of the enforcement action.

Within the areas inspected, no violations were identified.

8.

Action on Previous Inspection Findings (92701, 92702)

a.

(Closed) VIO 327, 328/91-08-01, Failure to Correct a Condition Resulting in Continued Flooding of Manholes for IE Cables. This violation was issued due to the licensee's failure to take corrective actions for continued problems associated with flooding of manholes containing safety-related diesel generator cables.

These problems originally occurred from 1989 to May 1991. This issue was also reviewed for closeout and discussed in Inspection Report 327,328/92-27.

In that report, the inspectors identified a weakness in which the licensee had not fully implemented successful corrective actions in a timely manner. Specifically, as identified by the licensee, followup PMs were not scheduled for

,

several of the identified MH/HHs with standing water, and PMs were j

not completed in a timely manner.

Inspection Report 327,328/92-27 identified that the issue would remain open pending the licensee's closecut of SQFIR920006 and additional NRC review of that closeout.

The inspectors reviewed a draft copy of the close-out for SQFIR920006, dated April 1,1993, in which all corrective actions were completed (final review by QA had not been completed). The

-

l l

..,.

,

.

inspectors also reviewed a small sample of completed work packages for PM 052053000, performed on December 28, 1992, February 22, 1993, and March 23, 1993. Approximately 12 inches of water was found in manhole / handhold SQN-0-MNWY-317-MH7B during the performance of PM 052053000 on February 22, 1993.

In response, the licensee scheduled and performed PM 020660000 on March 3, 1993, to investigate and resolve the standing water in manhole 78.

The licensee identified that the cause of the standing water was due to an unplugged power cord on the sump pump.

The PMs were performed at the proper frequency.

The inspectors concluded that licensee corrective actions for this violation were adequate, based on review of the above PMs, the licensee's activities toward the completion of SQFIR920006, and discussions with licensee personnel involved.

b.

(Closed) VIO 327/91-31-01, Failure to follow and/or Provide Adequate Procedures for Implementation of Maintenance Activities Associated With Packing of the Unit 1 MSIVs. The issue involved a failure to properly establish or implement procedures, resulting in inoperability of the Unit 1 main steam isolation valves. The licensee responded to the violation in a letter to the NRC dated March 9, 1992.

In that letter the licensee committed to conduct a review cf procedures to ensure that appropriate post-maintenance testing and verifications are properly specified; to establish a separate administrative process to control the issuance,

placement, and removal of jumpers; to reinforce maintenance staff

per'ormance cascading training on verification requirements and configuration control; and to implement a maintenance supervisory development program.

!

The inspectors reviewed the licensee's commitments and verified that they have been implemented as described.

In addition, the

'

inspectors reviewed recent maintenance performance with regard to jumper controls and noted improvement. Additional reviews of programmatic enhancements will be accomplished during closeout of Violation 328/92-22-02 which was discussed in NRC Inspection Report 327, 328/92-22.

The inspectors reviewed the major backlog items that were open at c.

the time of restart of both Sequoyah Units in 1988.

The purpose of this administrative review was to determine if the licensee had satisfied commitments from the 1988 SER (Unit 2 restart) and 1989 SER (Unit I restart), and commitments from other docketed information. The inspector reviewed a letter dated November 19, 1990, from the licensee to the NRC, which identified the status of all post-restart commitments.

The letter identified that eleven commitments made by the licensee to justify the restart of Unit I and 2 were not yet complete.

These commitments were associated with: steam generator lower support configuration, long term

'

procedure upgrade program, surveillance instruction enhancement program, cable routing program, Design Basis Verification Program

,

..,.

,

.

i Phase 2, resolution of ircorrect pipe support allowable stress criteria, DBVP lower steam generator supports, qualification of platforms, Phase I of the Q-list, replacement of temperature control valves, and welding program procedural development. The inspector verified that the above issues were identified as closed by the licensee's commitment tracking system.

In addition to the above issues, other major issues and commitments existed at the time of restart of both units in 1988, including:

-

Civil issues associated with large bore and small bore pipe supports, thermal expansion of platforms (evaluations and modifications).

-

Issues associated with Control Room Design Review (CRDR)

(NUREG 0737 issues).

-

The licensee's Replacement Items Project (RIP) associated with dedication of commercial grade material.

-

Fire modifications and implementation of the procedural corrective actions associated with TVA's deviation requests, and modifications and procedures associated with TVA's Appendix R program.

-

Completion of Regulatory Guide 1.97 issues i

The inspectors discussed the above backlog items with the licensee and reviewed how the licensee administratively tracks the status of open commitments.

The licensee indicated that all the above commitments had been satisfied, except for CRDR Category 3 Human Engineered Deficiencies (low safety significance).

These items will be completed during each units' cycle 6 refueling outage.

Within the areas inspected, no violations were identified.

9.

Exit Interview The inspection scope and results were summarized on May 4, 1993 with those individuals identified by an asterisk in paragraph I above. The

'

inspectors described the areas inspected and discussed in detail the inspection findings listed below.

Proprietary information is not contained in this report. Dissenting comments'were not received from the licensee.

Item Number Description and Reference