IR 05000416/1999004

Insp Rept 50-416/99-04 on 990131-0320.Violations Noted. Major Areas Inspected:Operation,Maintenance,Engineering & Plant Support

ML20206B366
Person / Time
Site:	Grand Gulf
Issue date:	04/23/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20206B364	List: IR 05000416/1999004 ML20206B360
References
50-416-99-04, 50-416-99-4, NUDOCS 9904290221
Download: ML20206B366 (24)

Text

i

.,.

j

'

.

ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-416 License No.: NPF-29 Report No.: 50-416/99-04 Licensee: Entergy Operations, In Facility: Grand Gulf Nuclear Station Location: Waterloo Road, Port Gibson, Mississippi 39150 Dates: January 31 through March 20,1999 Inspectors: John Russell, Acting Senior Resident inspector Peter Alter, Resident inspector Approved By: Joseph Tapia, Chief, Project Branch A ATTACHMENT: SupplementalInformation l

l l

'

.

-9904290221 990423 7

PDR ADOCK 05000416 '

G PDR ;c I

i a

.

EXECUTIVE SUMMARY Grand Gulf Nuclear Station NRC Inspection Report No. 50-416/99-04 This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 7-week period of resident inspectio Operations

A reactor startup and plant heatup performed on January 27,1999, was conducted properly and in accordance with existing procedures. No procedural or Technical Specification (TS) violations occurred; however, two instances of operator inattention to detail occurred. An inadvertent entry into a TS 3.3.6.1 action staternent for a period less than the allowed action time resulted when automatic main steam isolation on low condenser vacuum was bypassed with main turbine stop valves open, and an automatic shutdown of the reactor water cleanup (RWCU) system on high filter /demineralizer inlet temperature occurred due to an inappropriate valve alignment for plant heatup (Section 01.2).

• A reactor startup and plant heatup performed on March 1,1999, was well conducte Operator performance and attention to de' ail showed considerable improvement over the January 27,1999, plant startup (Section 01.3).

Licensed operator actions in the simulator during an emergency preparedness drill were good. Emergency operating procedures were effectively implemented, comrnunications were good, and effective training was provided. Licensee response to an inspector's observation that postaccident monitoring recorders for drywell radiation did not have the units of measurement displayed (rads per hour) in the simulator or in the main control room was good, because the licensee subsequently displayed these units in the main control room. The licensee also planned to assess other postaccident monitoring instrumentation for similar concerns (Section 04.1).

Maintenance

Maintenance and Engineering personnel demonstrated a lack of attention to ensuring that design drawings and calculations remained valid. The position of an American Society of Mechanical Engineers (ASME) Class 3 pipe was changed in a support as a result of a welding activity, but the effects of the support no longer acting to completely support the pipe deadweight and the differences between the as-left pipe support configuration and the applicable drawing were not rigorously considered. Failing to identify this condition adverse to quality, deviating from the support drawing and the i associated pipe stress calculation, was a noncited violation of 10 CFR Part 50, j Appendix B, Criterion XVI. This violation is in the licensee's corrective action program as Condition Repori (CR) 1999-339. The weld itself was performed satisfactorily (Section M1.2). i i

• Time response testing of reactor protection system functions was performed in compliance with TS Surveillance Requirement (SR) 3.3.1.1.15. The licensee was l

J

.

I

<

-2-responsive to an inspector's observation of a poor practice that, because the total response time was measured in parts and at different times, no acceptance criterion ,

was being applied to some data until approximately 15 months after the data was )

obtained. The surveillance periodicity and acceptance criteria were being met because j

'

total response time was summed and verified to be less than the TS allowable time within TS allowed intervals (Section M1.4).

• Maintenance activities associated with two recent main condenser seal failures were J acceptable. A 1999 main condenser to main turbine seal failure was influenced by j installing the seal joint in 1995 at a location with the maximum vendor recommended turbine to condenser vertical offset. Additionally, oil introduced into this same seal joint area at some point prior to 1995 caused an earlier seal failure in 1995. Both these failures resulted in unplanned forced outages. Actions taken in accordance with the Maintenance Rule for the 1995 failure were appropriate because no industry information was available to anticipate the 1999 seal failure (Section M2.1).

Enaineerina a Control of plant scaffolding was weak with respect to the length of time scaffolding was allowed to remain in place and with respect to the use of nylon straps to secure the scaffold to structural members. A noncited violation of 10 CFR Part 50, Appendix B, Criterion V, was identified when the licensee erected permanent scaffolding in containment without following procedures for plant changes, including performing a safety evaluation. The scaffolding had been in place for approximately 2 years. This violation is in the licensee's corrective action program as CR 1999-0259. Also, the translation of calculational assumptions into procedures for the use of nylon straps needed improvement. The licensee's response to these concerns was good (Section E2.1).

• Engineering initially performed a poor operability assessment of a through-wall pipe flaw in the standby service water (SSW) system, resulting in a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, for failing to follow Technical Requirements Manual 6.4.2 and 6.0.1 required actions for flawed ASME Class 3 components. This violation is in the licensee's corrective action program as CR 1999-0250. Separately, engineering also was not proactive in responding to an issue of excessive cycling of SSW relief valves, resulting in valve seat leakage, which was originally raised by the NRC in a 1996 inspection (Section E2.2).

l

Engineering response to indications of a degraded SSW flow indicator was goo Engineering troubleshot the issue successfu!!y, found through-wall leakage on the underwater sensing lines, and isolated the degraded piping from the main system recirculation line (Section E2.2).

Plant Sucoort

• Health Physics actions in response to an unanticipated unit shutdown were good. Areas within the radiologically controlled area were surveyed for changing radiological

I

.

,

3-conditions expeditiously, survey maps were updated and posted, and the general workforce was aware of the new radiological conditions (Section R1.1).

Station emergency response organization (ERO) performance in the technical support (TSC) center during the first 1999 quarterly emergency preparedness training drill showed considerable improvement from previously observed drill Communications between the emergency response facilities and prioritization of response teams were significantly better than past drills. The addition of engineers to the TSC staff and the increased use of licensed and certified senior reactor operators were strengths (Section PS.1).

l

,

.

i

!

-

\

ReDort Details Summarv of Plant Status - j The plant began the inspection report period at 50 percent power, with power ascension in ,

progress. The plant had been shut down in order to investigate degradation of current j transformers in the balance of plant and Class 1E switchgear. One hundred percent power was j achieved on February 1,1999. The plant operated at 100 percent power until February 21, 1 1999, when operators manually tripped the reactor from approximately 87 percent powe Operators received indications that the high pressure main condenser (the Condenser A) seal was leaking, placing main condenser vacuum in jeopardy. Operators initially decreased reactor

'

recirculation pump speed, to lower power to 87 percent, and then manually tripped the reacto Mode 4 was achieved on February 22,1999. The plant remained in Mode 4, the Condenser A and C seats were replaced, and on March 1,1999, a reactor startup was performed. The main I turbine was synchronized to the grid on March 2,1999. Power ascension was commenced, !

and the plant was held at approximately 50 percent power, when the operators were unable to place a second heater drain pump in service. One hundred percent power was achieved on 3 March 5,1999. The plant was operated at 100 percent power for the remainder of the j inspection report perio . ODerations 01 Conduct of Operations

'

01.1 General comments (71707)

The inspectors performed control room observations to ascertain operator knowledge 3 and performance. Operations shift turnovers and briefings were thorough and well )

conducted, Operators were knowledgeable of the status of equipment, and applicable TS limiting conditions fc,r operations (LCO) were appropriately documente The inspectors also observed off-normal operations in the control room and in the plan These observations included: plant cooldown using safety relief valves dumping steam to the suppression pool, establishing shutdown cooling, and placing the secondary plant in long path recirculation. These infrequently performed evolutions received excellent

- planning t.nd were performed with good control of the evolutions by control room operator i i

O1.2 January 27.1999 Reactor Startuo Inspection Scope (71707)

On January 27,1999, the inspectors observed portions of the plant startup following an unplanned maintenance outage to replace current transformers in safety-related 4160 VAC switchgear. The inspectors reviewed applicable portions of Integrated j

. Operating Instruction 031-01-1, Revision 109, " Cold Shutdown to Generator Carrying Minimum Load."

!

,

~

t

.

.

'

-2- Observations and Findinas Generally, the reactor plant startup was conducted in accordance with applicable procedures, comprehensive briefs were conducted before each evolution, and the operators used formal three way communications and kept the chemistry and health physics departments advised of the progress of the startup as required. Two examples of operator inattention to detail were observed as described belo With the mode selector switch selected to STARTUP during the reactor and steam plant heatup, the operators observed that the Group i main steam system isolation for low main condenser vacuum was bypassed with the main turbine stop valves open. TS I able 3.3.6.1-1 requires that the low condenser vacuum Group I isolation be operable in Mode 2 (Startup) whenever the turbine stop valves are not closed. The turbine stop valves were immediately closed. The condition had existed for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, therefore, the required LCO action completion time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> was not violated. The shift superintendent stated to the inspectors that the low vacuum isolation was bypassed and the *MN CNDSR VAC LO BYP" annunciator was illuminated, when he directed that preparations be made for main turbine startup in accordance with Procedure 03-1-01 1 Section 7.1," Turbine Startup." While concurrently performing Procedure 03-1-01-1 Section 6.0," Unit Heatup," he became aware of the action requirements of TS 3.3. The operators wrote CR 1999-0122 to document the event and init. ate a change to Procedure 03-1-01-1 to reference TS 3.3.6.1 more appropriately. The inspectors determined that operator inattention to detail and failure to recognize the significance of the low main condenser vacuum bypass annunciator while opening the main turbine stop valves led to the inadvertent entry into TS 3.3. During the reactor and steam plant heatup, the operators found that the RWCU system was not properly aligned to let down water from the reactor to the main condenser to j allow for thermal expansion during reactor heatup. Before action could be taken to l correct the system lineup, the RWCU system shutdown automatically because of a high temperature condition at the inlet to the RWCU filter /demineralizers. This high temperature condition shut valve G33F004, the RWCU pump suction outboard containment isolation valve, which tripped the operating RWCU pump on interlock. The operator at the controls stated that RWCU system was lined up in accordance with Section 5.2, " Sampling at Low Reactor Pressure," of System Operating instruction 04-1-01-G33-1, Revision 104," Reactor Water Cleanup System." This lineup bypassed the regenerative and nonregenerative heat exchangers to allow for chemistry sampling of reactor water while the reactor was in cold shutdown. This lineup effectively eliminated any cooling of system flow during the reactor heatup. The operators also noted that step 3.3.3.a. of the prestartup checklist portion of Procedure 03-1-01-1 only requires ,

that the RWCU system be "In OPERATION per SOI 04-1-01-G33-1. . . " without specifying that the system heat exchangers not be bypassed (for sampling at low pressure). The operators wrote CR 1999-0123 to document the event and proposed a change to the prestartup checklist portion of Procedure 03-1-01-1 and a system restoration section for Procedure 04-1-01-G33-1 following reactor water sarnpling at low reactor pressure. The inspectors determined that operator inattention to detail and failure to recognize an improper RWCU system lineup caused an automatic high temperature shutdown of the RWCU syster .

.

3- Conclusions A reactor startup and plant heatup perfonned on January 27,1999, was conducted properly and in accordance with existing procedures. No procedural or TS violations occurred; hov. aver, two instances of operator inattention to detail occurred. An inadvertent entry into a TS 3.3.6.1 action statement for a period of time less than the allowed action time resulted when the automatic main steam isolation on low condenser vacuum was bypassed with main turbine stop valves open and an automatic shutdown of the RWCU system on high filter /demineralizer inlet temperature occurred due to an inappropriate valve alignment for plant heatu O1.3 March 1.1999. Reactor Startuo 1 Inspection Scope (71707)

l The inspectors observed portions of the plant startup following an unplanned I maintenance outage to replace the main condenser boot seal. The inspectors reviewed applicable portions of Integrated Operating Instruction 03-1-01-1, Revision 110 " Cold Shutdown to Generator Carrying Minimum Load." ,

i Observations and Findinas l The startup was generally conducted in accordance with applicable procedure Comprehensive briefs were conducted before each evolution and operators used formal three-way communications. Operators also kept the chemistry and health physics departments advised of the progress of the startup. The operators' performance and attention to detail resulted in an event-free reactor startup and power ascension to full power. The inspectors noted that the startup was delayed for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> due to problems with air operated level and flow control valves in the heater drain system. The inspectors observed improved operator performance during the reactor plant startup as compared to the previous startup at the beginning of this inspection perio Conclusions A reactor startup and plant heatup performed on March 1,1999, was well conducte Operator performance and attention to detail showed considerable improvement over the January 27,1999, plant startu Operator Knowledge and Performance 04.1 Operator's Performance Durina Emeraency Preparedness Drill Inspection Scope (71707)

On February 10,1999, the inspectors observed an operating crew in the plant simulator participating in an emergency preparedness drill. The inspectors reviewed portions of NUREG 0737," Clarification of TMI Action Plan Requirements," Regulatory Guide 1.97, l

t l

l l

'

[

r

.

,

-4-

" Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and !

Eno o Conditions During and Following an Accident," and Grand Gulf TSs. The inspectors observed the critique by emergency preparedness and simulator instructor personnel of operating crew performance, conducted immediately after drill terminatio b. Obsentations and Findinas The simulator scenario included a fire in the Division ill emergency diesel generator switchgear room and then a loss of main turbine electrohydraulic control which resulted in a main turbine trip. The control rods failed to insert and alternate methods of reactor shutdown were disabled. Both containment airlock doors failed, providing for a release j of radioactivity from the containment. Because the safety relief valves were being l operated and preexisting fuel clad leakage was present, a release occurred in the l scenari The operating crew effectively implemented the emergency operating procedures and mitigated the event to the extent possible given the event scenario. Communications between operators and cross-checking of control board manipulations were good. The shift superintendent appropriately declared emergency conditions. Minor areas for improvement were noted by the simulator instructors and were effectively brought to the l operating crew's attention during the postdrill critique. Overall, the inspectors found that l the operating crew's performance was good and the training was effectiv The inspectors did note one issue not addressed during the postdrill critique. Some postaccident monitoring instrumentation for containment radiation did not indicate the units of measurement. This caused some confusion during the drill when the safety parameter display system failed and operators began using control room recorders to provide indication of containment radiation levels, but they were not sure v/hether the instrumentation read in rad, rem, millirad, or millirem per hour. Specifically, Recorders !

1D21-RR-R601 A and 1D21-RR-R601B, the Trains A and B containment drywell j radiation w;de-range recorders, did not indicate units of measurement. The inspectors later verified this was also true in the actual control room. In response to the inspector's observation, the licensee subsequently provided indicated units of measurement for i these recorders in the actual control room. The licensee also planned to evaluate all accident monitoring instrumentation for proper unit indication. The inspectors found the licensee's actions responsive to the concer c Conclusions

Licensed operator actions in the simulator during an emergency preparedness drill were good. Emergency operating procedures were effectively implemented, communications were good, and effective training was provided. Licensee response to an inspector's observation that postaccident monitoring recorders for drywell radiation did not have the i

units of measuremert displayed (rads per hour) in the simulator or in the main control

'

room was good. The licensee also planned to assess other postaccident monitoring instrumentation for any similar concern .

5-11. Maintenance M1 Conduct of Maintenance M1.1 General Maintenance Comments Inspection Scoce (62707)

The inspectors observed portions of the following maintenance activities:

Clean an Engineered Safeguards Feature Switchgear Room Cooler Flow Element, Work Order 219992

Troubleshoot Control Room Air Conditioning Unit A

Cut and Cap Instrumentation Lines for SWS Train B Recirculation Flow Indicator, Work Order 990066 Observations and Findinas The inspectors found that the work performed during these activities was thorough. All work observed was performed with the work package present and in active use, except for troubleshooting the Train A control room air conditioning unit which was performed in accordance with the licensee program using verbal authoriza' ion from the Shift Superintendent and with no written work package. The inspectors frequently observed supervisors and system engineers monitoring job progress. Quality control personnel were present whenever required by procedure. When applicable, appropriate radiation controls were also in plac M1.2' Replace Tailoice for Valve 1P41F299A. the Train A SSW Relief Valve

- Insoection Scoce (62707)

l On March 10,1999, the inspectors observed welders performing portions of Work Order 00218892, replacing the tailpipe for Valve 1P41F299A. The inspectors reviewed portions of Mechanical Standard GGNS-MS-16, Revision 26, " Hangar Installation Criteria," applicable portions of the ASME Code, Sections lit and IX,1989, and Weld i Procedure Specifications E-P1-A-A1 R/1 and E-P1-TA-A1 R/1. The inspectors also reviewed pipe support Drawing Q1P41G010C03, Revision 0, " Standby Service Water Basin "A" Pumphouse and Associated Piping." Observations and Findinas

,

-

The tailpipe for Valve 1P41F299A is ASME code Class 3,8-inch, carbon steel pipin The piping originates from Valve 1P41F299A, runs horizontally approximately 6.5 feet, turns down 90 degrees and runs vertically approximately 5.5 feet, then it runs through a square pipe support at the floor level and ends in the Train A SSW basin. The square pipe support, prior to the replacement of the horizontal section of piping performed using

F a

.

-6-Work Order 00218892, supported the pipe in the vertical direction as a dead weigh The pipe has four lugs welded to the pipe exterior wall which, prior to the maintenance, contacted the square support providing the vertical support. The pipe also had a 1/16-inch clearance from the square, iron support prior to the maintenanc Drawing Q1P41G010 C03 showed the 1/16-inch clearance as well as the pipe lugs contacting the pipe suppor The weld performed was a ASME Code P1 carbon steel to P1 carbon steel material weld, using gas tungsten arc welding for the first two weld beads, then shielded metal arc welding for the remaining weld beads. Based on observation, the inspectors found that the welding was ~p erformed as directed by the applicable weld procedure specification and the Welder Technique Sheets that provided instructions for completing the wel On March 16,1999, the inspectors observed the as-lef t position of the tailpipe in the support described above. The welders had shifted the pipe position in order to obtain proper fit up for the weld. The pipe was shifted so as to have no clearance on two sides of the support, and all four lugs were such that clearance existed between the support and the lugs. Also, the horizontal run of pipe appeared slightly sloped. Consequently, the support no longer supported the dead weight of the pipe as shown in Drawing Q1P41G010103. Licensee maintenance personnel had noted, after the weld was completed, that the pipe had no clearance on two sides of the support. Based on consultation with system engineering, maintenance personnel considered this condition as acceptable because the SSW system was not anticipated to exceed 150* Mechanical Standard MS-16 allowed ne clearance from pipe supports for systems below 150*F, because the effects of temperature induced pipe expansion and contraction were minimal. However, the licensee failed to consider the effect on the pipe analysis, given that the support no longer provided complete deadweight support. The inspectors also questioned whether the pipe had been cold sprung, inducing stresses in the pipe due to some amount of force being applied by the support, to the pipe in the locations of no clearance.10 CFR Part 50, Appendix B, Criterion XVI, states, in part, that conditions adverse to quality, such as deviations, are promptly identified and corrected. Contrary to this, the licensee failed to identify, and consequently correct, that the as-left support and pipe configuration deviated from the applicable drawing, and from applicable pipe stress calculations, until this was questioned by the inspectors. This was a violation of 10 CFR Part 50, Appendix B, Criterion XVI. This Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-416/9904-01). This violation is in the licensee's corrective action program as CR 1999-339. The licensee performed an interim operability assessment, crediting the support with providing some deadweight support, due to friction in the areas of no clearance, which concluded that pipe stresses remained acceptable. The licensee planned to perform a root cause analysis to determine the reasons the pipe support was considered acceptable upon termination of the welding activity and planned to perform maintenance to center the pipe in the support with pipe lugs contacting the support. The inspectors found these proposed actions adequate. The inspectors found that failing to consider all aspects of the as-left position of the Valve 1P41F299A tailpipe in the pipe support was indicative of a lack of attention to ensuring applicable drawings and I

calculations remained vali <

)

.

.

-7- )

I Conclusions Maintenance and Engineering personnel demonstrated a lack of attention to ensuring that design drawings and calculations remained valid. The position of an ASME Class 3 pipe was changed in a support as a result of a welding activity, but the effects of the support no longer acting to completely support the pipe deadweight and the differences between the as-left pipe support configuration and the applicable drawing were not rigorously considered. Failing to identify this condition adverse to quality, deviating from the support drawing and the associated pipe stress calculation, was an NCV of 10 CFR ,

Part 50, Appendix B, Criterion XVI. This violation is in the licensee's corrective action !

program as CR 1999-339. The weld itself was performed satisfactoril l l

'

M1.3 General Surveillance Comments Inspection Scoce (6172Q1 The inspectors observed the performance of portions of the following surveillances: i a

Control Room Standby Fresh Air Unit B Blower Test (06-OP-SZ51- M-0002)

• Daily Operating Logs (06-OP-1000-D-0001) Observations and Findinas The inspectors noted that the test procedures provided clear guidance and properly implemented TS requirements. Measuring and test equipment was verified to be within !

the current calibration cycle. When appropriate, the applicable LCO was entered when the instrumentation was removed from service. The operators and technicians were knowledgeable and qualified. As-found test data was within the tolerance established for the instrumentation. The inspectors verified that the tests had been previously performed at the correct periodicit M1.4 Procedure 06-lC-1B21-R-2023. " Sensor Response Time Test" j Inspection Scope (61726)

On February 18,1999, the inspectors observed contract personnel performing portions of Procedure 06-lC-1B21-R-2023, Revision 100," Sensor Response Time Test." The inspectors discussed the methodology used to perform the sensor portion of this surveillance with a member of the instrumentation and Controls Branch, NRC Office of Nuclear Reactor Regulation and licensee personnel. The inspectors also reviewed Procedure 06 IC-1C71-R-0006, Revision 100, Attachment IV, " Turbine Control Valve (RPS/RPT) Electronics Time Response Test Channel D," performed February 21,1999, and a separate Attachment IV performed July 31,1997. The inspectors reviewed Procedure 06-lC-1821-R-0038, Revision 100, " Reactor Vessel Steam Dome Pressure (RPS) Electronics Time Response Test Channel D," performed January 20, 199 I

.

.

8- Obsentations and Findinos The surveillances mentioned above were being performed in order to satisfy TS SRs 3.3.1.1.15, Functions 3 and 10 of Table 3.3.1.1-1. This SR was to verify that the reactor protection system response time for steam dome pressure high was less than 0.35 seconds and less than 0.10 seconds for turbine control valve fast closure. The periodicity for both of these SRs was every 18 months, on a staggered basis (i.e., one channel each 18 months). Based on the data reviewed and observation of portions of sensor response time measurement, the inspectors found that the licensee was satisfying these two SRs. The licensee was measuring the sensor response time and, at a separate time, the electronics response time and then adding the two times to ensure the total was less than the TS required maximum time. This methodology was acceptable. The licensee was also using a frequency analvsis to determine sensor response time for these two instruments, as opposed to hydraulically changing the state of the sensor and directly measuring response time, which was also acceptabl The inspectors noted that the data was totaled and compared to the TS allowable time at the completion of the electronics time measurement and that the previous data measured for the sensor was not utilized until the electronics time data was measure For Channel D of the turbine control valve closure, the sensor data was obtained in October 1997, and the electronics data was obtained in February 1999. Consequently, about 15 months lapsed before the sensor data was compared to any limits. In response to this concern, the licensee was evaluating whether to change their procedures to provide for separato acceptance criteria for the sensor and electronics portions of the measurement, or whether to use the data as it was obtained along with the most recent data for the sensor or the electronics to compare to TS allowable. In either of these two ways, data would be used to detect degradation of the time response each time the data was obtained instead of waiting for a complete set of new sensor and electronics data before TS limits were checked. The inspectors found this responsive to the concern, considering that the methodology in place complied with T c. fonclusions Time response testing of reactor protection system functions was performed in compliance with TS SR 3.3.1.1.15. The licensee was responsive to an inspector's observation that, because the total response time was measured in parts and at different times, no acceptance criterion was being applied to some data until approximately 15 months after the data was obtained. The surveillance periodicity and acceptance criteria were being met be'cause total response time was summed and verified to be less than the TS allowable time within TS allowed interval ,

>

.

! -

-9-M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Main Condenser Seal Failure Inspection Scoce (62707)

The inspectors reviewed the circumstances of the main condenser seal failure that prompted operators to shut down the unit on February 21,1999. The inspectors visually inspected replacement seals and interviewed licensee personnel. The inspectors reviewed portions of NRC inspection Reports 50-416/95-12,50-416/95-14, and 50-416/96-13, and Licensee Event Reports 50-416/39012 and 50-416/950 Observations and Findinas The main turbine and the main condenser are sealed by three approximately 10-inch wide seals, one seal for each low pressure turbine to condenser interface. The seals are held in place by a series of clamps. The outer portion of the seat is covered by a water reservoir. The inspectors noted two previous failures of the seal between the main turbine and the main condenser. In 1989, the plant experienced an automatic reactor scram due to a main turbine trip caused by lowering condenser vacuum. A 3-foot section of Seal A (the highest pressure low pressure turbine) had torn near the retaining clamps. All three seals were replaced. The original hemp reinforced rubber seal was replaced with polyester reinforced rubber. The original seal had been installed since plant construction and was placed in service in 1985. During July 1995, the plant experienced another automatic reactor scram due to n main turbine trip caused by lowering condenser vacuum. The Seal A joint had failed, causing the joint to tear. The licensee discovered the presence of oil on the rubber which led to a degradation of the joint. The seals were replaced with a seal fabricated from reinforced neoprene rubber which was more resistant to oil induced degradation. The condensate system was maintained in the a(1) category of 10 CFR 50.65, the Maintenance Rule, from August 1995 until August 1996 because of the reactor trip caused by the failed seal. Based on licensee comments, the inspectors found that no industry information was available to anticipate the 1999 seal failur The seal failure during February 1999 was caused by a tear near Seal A, propagating from the seal joint. Seal C was also found to have bubbling in the joint area. The seal joints were made by joining the two end pieces of the seal using a vulcanization process. The vulcanization was performed by the seal vendor. The Seal A joint had been placed in an area which had approximately a one inch vertical offset between the condenser and the turbino. This was the maximum offset recommended by the vendo Seals A and C were replaced and joined using an enhanced vulcanization technique performed by the vendor, with increased (from 1995)liensee oversight of the proces The seal joint location was also shifted to another locabon which had less than the one inch vertical condenser turbine offset. At the end of the inspection report period, the licensee was evaluating placing the condensate system in Category a(1) of the Maintenance Rul p

.

.

-10-The inspectors found that the 1995 seal failure was probably caused by oil introduced into the sealjoint area from the main turbine. The licensee had installed a cover plate on top of the seal reservoir to prevent this from happening again. Licensee response to the 1995 failure was appropriate in terms of the Maintenance Rul Conclusions Maintenance activities associated with two recent main condenser seal failures were acceptable. A 1999 main condenser to main turbine seal failure was influenced by installing the seal joint in 1995 at a location with the maximum vendor recommended turbine to condenser vertical offset. Additionally, oil introduced into this same seal joint area at some point prior to 1995 caused an earlier 1995 seal failure. Both of these failures resulted in unplanned forced outages. Actions taken in accordance with the Maintenance Rule for the 1995 failure were appropriate because no industry information was available to anticipate the 1999 seal failur . Enaineerina E2 Engineering Suppon of Facilities and Equipment E2.1 Controlof Scaffoldina Inspection Scope (37551) ,

l During this report period, the inspectors walked down various plant areas. The inspectors reviewed portions of Engineering Calculation CC-N1000-92068, Revision 0,

" Evaluation of Standard Scaffolding Configurations For Standard No. GGNS-CS-05,"

Standard Number GGNS-CS-05, Revision 0," Standard for Erection of Scaffolding in ,

Safety Related Areas," and Procedure 15-S-01-106, Revision 1," Scaffolding Erectiont l The inspectors also reviewed portions of Procedure 01-S-16-1, Revision 102, " Plant !

Change implementation," Procedure 01-S-17-5, Revision 6, "Enginearing Request," and '

Procedure 01-S-17-2, Revision 1, " Change Review Board Process." The inspectors also interviewed relevant licensee personnel involved in the design and control of scaffoldin Observations and Findinas On February 5,1999, the inspectors observed an approximately 20-foot tall scaffold i erected on the 185-foot elevation of containment. The scaffold had a red lamicoid tag affixed, which indicated the scaffold was permanent. The scaffold was less than 6-inches from safety-related residual heat removal piping. The inspectors reviewed Grand Gulf Scaffolding Request Form LT-00595, which indicated that this scaffolding had been erected on October 20,1996. The scaffold request form indicated the scaffold would be needed until November 15,1996, in order to operate a valve. The inspectors were informed by licensee personnel that Operations had requested that the scaffold remain in place after November 15,1996, because the scaffold facilitated a quarterly surveillance for Valve G41F260. The inspectors were also informed that there

. .

l f

p

'

.

i i

was no plan to remove the scaffolding. No safety evaluation had been performed to determine the effects of the scaffolding on containment design and the functioning of safety-related equipment during postulated accident conditions. Because the scaffolding had been in place for over 2 years and was labeled as permanent, and because the licensee had no plans to remove the scaffolding, the inspectors found that the scaffolding was a plant change as controlled by Procedure 01-S-16-1. Procedure

'

01-S-16-1 stated, in step 6.1.1, that plant changes were initiated, reviewed, and approved in accordance with Procedures 01-S-17-2 and 01-S-17-5. The scaffold described above was not initiated, reviewed, and approved in accordance with either of these procedures. These procedures provided for the engineering request procecs and the change review process, which required engineering review and a safety analysis screening for all plant changes.10 CFR Part 50, Appendix B, Criterion V, states, in part, that matters affecting quality shall be accomplished in accordance with procedure Installing the scaffolding described above as a permanent change to the structure inside containment without performing the installation in accordance with Procedure 01-S-16-1 was a violation. This Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 1999-0259 (NCV 50-416/9904-02).

On March 19,1999, the licensee informed the inspectors that three other long-term scaffolds in safety-related areas had been identified in the Residual Heat Removal B room and on the 185- and 93-foot levels of the auxiliary building. The licensee planned to either remove these scaffolds or perform safety evaluations if radiation levels did not permit scaffold removal. The licensee also planned to change their scaffold program such that, if a scaffold was erected in a high radiation area for a task of less than 18 month periodicity and the scaffold remained in place for greater than 18 months, a safety evaluation would be performed and a request initiated to install a permanent platform. Scaffolding for tasks greater than or equal to an 18-month periodicity would be removed upon completion of the task. The inspectors found these planned corrective actions responsive to the concer The inspectors also observed that some of the scaffolds mentioned above and a scaffold erected adjacent to the spent fuel pool observed on February 5,1999, were secured to plant structural members by nylon straps, and not with any type of metal clamps. The inspectors were informed by design engineering personnel that, by design, the maxirnum moment in a horizontal direction applied to scaffolding was 900 foot-pounds. Consequently, in order to maintain the scaffold attached to the structural member, the nylon straps were assumed to maintain the joint, given a moment of 900 foot-pounds. The inspectors noted that, as observed for the scaffolding adjacent to the spent fuel pool, the nylon strap would resist movement of the secured scaffold pipe in proportion to the amount of friction applied by the strap. However, Procedure 15-S-01-106 or Construction Standard GGNS-CS-05, did not provide guidance for how tightly the nylon straps were to be wrapped,'which would determine how much friction was

! applied. Consequently, the relatively smooth scaffold pipe could slide within the nylon I

strap joint if the nylon straps were not wrapped tight enough, given design basis forces in the horizontal direction. Not completely controlling the tightness of the joints secured with nylon strap was a weak practice. This would provide for greater than an assumed 6-inch horizontal displacement described in GGNS-CS-05. In response, the licensee l

l u

,

,

-12-was changing Construction Standard GGNS-CS-05 to provide for metal clamps in the areas where nylon straps viere used so that the nylon could by secured against the

+

clamp and the frictional force between the nylon and the pole would not determine joint strength. The inspectors found this response adequat . Conclusions i Control of plant scaffolding was weak with respect to the length of time scaffolding was allowed to remain in place, and with respect to the use of nylon straps to secure the scaffold to structural members. An NCV of 10 CFR Part 50, Appendix B, Criterion V, was identified when the licensee erected permanent scaffolding in containment without

' following procedures fo: plant changes, including performing a safety evaluation. The scaffolding had beer. in place for approximately 2 years. This violation is in the licensee's corrective action program as CR 1999-0259. Also, the translation of calculational assumptions into procedures for the use of nylon straps needed improvement. The licensee's response to these concerns was goo E2.2 Trains A and B SSW Minor Throuah-Wall Pioe Leakaae Insoection Scope (71707. 37551)  ;

The inspectors reviewed the circumstances surrounding, and licensee response to, minor SSW through-wall pipe leakage observed by the licensee during and before the inspection report period. The inspectors reviewed portions of NRC Generic Letter (GL) 91-18, Revisions 1 and 0,"Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions,"

and NRC GL 90-05, Revision 0,' Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1,2, and 3 Piping." The inspectors reviewed licensee CR CR-GGN-1998-0992, CR-GGN-1999-0218, and CR-GGN 1999-0250 and portions of Grand Gulf TS, the Technical Requirements Manual (TRM), and the Updated Final Safety Analysis Report (UFSAR), Section 9.2.1, * Standby Service Water System." The inspectors performed a limited walkdown of Trains A and B SSW piping, located in the SSW enclosure, and interviewed operations personnel and the SSW system and design engineer Observations and Findinas On September 24,1998, during performance of a quarterly Train A SSW Pump Valve 1P141C001 A inservice test, operations personnel observed approximately 5 to 10 drops leaking from a small through-wall pipe flaw on the pump discharge Relief !

Valve 01P41F299A tailpipe. The tailpipe is 8-inch carbon steel piping, ASME code Class 3, and routes relief valve discharge flow to the service water basin. The leak was ,

located just downstream (approximately 2 inches) of the relief valve at the bottom of the j

'

pipe, in the SSW Train A pump roo ;

I

'

i

.

-13-Valve Q1P41F299A (the relief valve) is located on the pump discharge piping, and provides overpressure protection for Train A E.SW, whether the train is aligned for recirculation back to the service water basin e r is aligned for flow through system load The SSW system is normally not oparating. During normal and automatic SSW starts, the relief valve would lift for some period of time. This was because the pump discharge (Valve F001 A) and recirculation (Valve F006 A) isolation valves were normally closed. ~

When the SSW pump started, Valve F001 A and/or Valve F006A (for Train A) wou!d receive an open signal, but since these 24-hch and 20-inch, respectively, motor operated valves took approximately 50 seconds to fully open, the initial pump discharge pressure would cause the relief valve to lift. Because the lifting during each pump start seemed to be an excessive amount of cychng for these valves, the inspectors reviewed portions of the UFSAR to determine if this was within system design. The UFSAR did not specifically describe the functioning of the relief valves during system start. The inspectors discussed excessive cycling of the relief valve with the system engineer who stated that this issue had been raised during an NRC inspection conducted in 1996. He also noted that the relief valves had experienced some seat leakage due to excessive cycling and that a design change was being considered to decrease the cycling of these valves. The inspectors reviewed NRC Inspection Report 50-416/96-02, which stated, in part, that it was a poor practice to use the safety relief valve to provide minimum flow recirculation for the pump. The inspectors found that the licensee was not proactive in responding, since 3 years had elapsed and a plan for resolution of the issue was not in plac As a result of the tailpipe leakage discussed above, on September 24,1998, the licensee generated CR 1998-0092. An operability assessment performed as a result of this CR found that SSW Train A was operable because the leak was small and, ccnsequently, SSW flow rate would r ot be affected and room flooding would not resul At that time, no consideration was given to ASME code requirements or TRM requirements. TRM 6.4.2 stated that, if the structuralintegrity of ASME Class 3 components did not conform to inservice inspection program requirements, then the component must be immediately isolated from service. A through-wall pipe flaw did not conform to inservice inspection program requirements. TRM 6.0.1 stated, in part, that, if a TRM action was not met, then the following actions shall be taken: (1) Develop and implement compensatory actions, (2) develop a plan for exiting LCO 6.0.1, and (3) obtain duty manager approval of the compensatory plan and exit plan for exiting LCO 6.0.1 within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The licensee failed to immediately remove the leaking tailpipe from service. The licensee also f ailed to develop compensatory actions, a plan to exit LCO 6.0.1, and obtain duty manager approval within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.10 CFR Part 50, Appendix B, Criterion V, states, in pa'1, that matters affecting quality shall be performed in accordance with procedures. Failing to take action in accordance wth the TRM was a violation of 10 CFR Part 50, Apoendix B, Criterion V. This Severity Level IV violation is being treated as an NCV, cons: stent with Appendix C of the NRC Enforcement Polic This violation is in the licensee's corrective action program as CR 1999-0250 (NCV 50-

,

416/9904-03).

l On February 25,1999, a system engineer recognized that CR 1998-0992 had been dispositioned without recognizing the TRM requirements. The licensee then entered TRMs 6.4.2 and 6.01. The li:ensee then performed an operability assessment of SSW

.

.

-14-Train A using guidance in NRC GL 91-18. NRC GL 91-18 (Revision 0) states that for Class 3 moderate energy piping (such as SSW), the acceptance criteria in NRC GL 90-05 may be used to support system operability, until relief is obtained from >

the NRC. The licensee performed portions of the operability criteria listed in NRC GL 90-05 as an interim measure, including nondestructive examination of the pipe wall, periodic inspections of the leak location, and minimizing pump starts. The licensee did not seek relief from the NRC. On March 10,1999, the tailpipe portion that contained the through-wall flaw was replaced. The inspectors viewed the interior of this tailpipe i portion and observed an approximate quarter inch through-wall flaw and pitting on the bottom of the pipe. The pitting was located where stagnant water would probably be located. Evidence of pipe wall erosion, apparently due to water flow, was eviden Preliminarily, the licensee assessed the cause of the degradation as either erosion / corrosion and/or corrosion caused by microbiological agents. Tha inspectors found that, as of February 25,1999, the actions described above satisfied the requirements of T.R.M. 6. On February 18,1999, operators were performing a quarterly Train 8 SSW pump inservice test. In order to achieve desired pump flow, the operators opened the pump recirculation isolation valve and then closed an isolation valve for main flow. As recirculation flow was adjus.ted, the Train B discharge relief valve lifted. Operators backed out of the surveillance and generated CR 1999-212 to investigate the relief lifting at too low a pressure. Operations and engineering subsequently evaluated system response and determined that the relief had lifted within specification and that the recirculation fiow gauge appeared to be reading erroneously. On February 23,1999, CR 1999-218 was generated to investigate. The licensee pressurized 1he 3/4 inch, carbon steel, ASME code Class 3 piping lines that provided pressure to the flow gauge from the recirculation line with compressed air in order to investigate the recirculation flow gauge sensing line integrity and check for leaks. Divers were used to inspect the underwater portion of these lines. Divers noted gas bubbles from both high and low pressure lines, indicating through-wali pipe flaws. The licensee generated a corrective action assignment for CR 99-0218, for design engineering to conduct an operability assessment. The licensee also entered TRM 6.4.2. The affected piping was isolated from service by verifying that the SSW Train B recirculation isolation valve (Valve P41- j F0068) was closed and by opening residual heat removal heat exchanger isolation valves. Valve P41 F006B b interlocked with these residual heat removal heat exchanger isolation valves and Valve P41-F006B will not receive an open signal if the residual heat removal valves are open. Information tags were used to control the valve positions. The inspectors found that this satisfied the requirements of TRM 6.4.2 to 1 immediately isolate the sffected piping from servic On February 27,1999, the licensee cut both gauge sensing lines 6 inches from the underwater recirculation line ai.J at the next support upstream from the recirculation piping, threaded the cut line on the recirculation pipe side, and installed pipe caps. The sectit.1 of pipes removed indicated that the exterior of the pipe was being degraded by the underwater environment and that a protective coatirg applied to the pipe exterior was degraded. At the end of the inspection period, the licensee was evaluating alternate flow indications for performance of the quarterly pump inservice test and i

_

l~

!~

f

.

-15-and leaving the flow instruments disconnected. The inspectors found that the licensee's diagnosis of the degraded flow indicator was good and response to the indication of through-wall flaws was goo Conclusions Engineering initially performed a poor operability assessment of a through-wall pipe flaw in the SSW system, resulting in a NCV of 10 CFR Part 50, Appendix B, Criterion V, for failing to follow TRMs 6.4.2 and 6.0.1 required actions for flawed ASME Class 3 components. This violation is in the licensee's corrective action program as -

CR 1999-0250. Sepsrately, engineering was not proactive in responding to an issue of excessive cycling of SSW relief valves resulting in valve seat leakage originally raised by the NRC in a 1993 inspectio Engineering responte to indications of a degraded SSW flow indicator was goo Engineering troubleshot the issue successfu!!y, found through-wall leakage on the underwater sensing ines and isolated the degraded piping from the main system recirculation lin ]

IV. Plant SuDDort R1 Radiological Protection and Chemistry Controls i R1.1 Radiolooical Postinas Inspection Scope f71750)

On February 23,1999, the inspectors toured portions of the radiologically controlled area and interviewed various plant personne Observations and Findinas On February 21,1999, the licensee manually scrammed the unit to repair a failed main condenser seal, as described in Section M2.1 of this report. On February 23,1999, radiological conditions in the radiologically controlled area changed from the conditions present during Mode 1 operations. The unit was being cooled by shutdown cooling and radiation levels in various locations had consequently increased. The inspectors )

observed that all surveys of potantially affected locations were updated as of j

'

February 22,1999, and were poeted outside of the appropriate room. All contaminated area, high contaminated area, radiation area, and high radiation area boundaries observed were clearly and appropriately posted. All workers interviewed were aware of the radiological conditions in which they were working. Health Physics personnel monitoring the radiologically controlled area entry and exit point were thorough. Based

'

on the timeliness of the radiological surveys and the awareness of the workforce of the changing radiological conditions, the inspectors found that Health Physics actions in response to the unanticipated unit shutdown were goo t'

,

,

,

O-16- Conclusions Health Physics actions in response to an unanticipated unit shutdown were good. Areas within the radiologically controlled area were expeditiously surveyed for changing radiological conditions, survey maps were updated and posted, and the general workforce was aware of the new radiological condition P5 Staff Training and Qualification in Emergency Planning P First 1999 Quarterly Emeraency Preoaredness Trainina Drill Insoecticn Scope (71750)

On February 10,1999, the inspectors observed the first 1999 quarterly emergency preparedness training drill at various locations. The performance of licensee personnel providing emergency response during emergency plan activities was observed. The inspectors reviewed Emergency Plan Procedure 10-S-01-30, Revision 7, " Technical Support Center (TSC) Operations." Observations and Findinas The training drill began with a fire in the Division lli engineered safety features (ESF)

switchgear room. Fire brigade access to the fire required passage through the Division I ESF switchgear room. Prior to the fire brigade responding to the scene of the fire, the drill controllers briefed the fire brigade members. During the brief, it was emphasized that a Division ll work week was ongoing and that, since Division I was the " protected train," care must be taken while passing through the Division i ESF switchgear roo The controllers and evaluators then closely monitored the passage of the fire brigade members and their firefighting equipment as they passed through the Division l ESF switchgear room. The inspectors considered this attention to actual plant conditions to be a strength on the part of the drill controllers and evaluator The emergency preparedness organization had turned over direct responsibility for the operation of the various emergency response facilities to the ERO members who staffed the individual facilities. The ERO members who staffed the senior positions on each team became " facility owners." These groups then set the standards for staff performance in each of the emergency response facilities. One change that resulted from this initiative was the assignment of system engineers to the TSC and maintenance plannen to the Operations Support Center. The availability of engineering support contributed to the effectiveness of the TSC. Another change was the assignment of licensed or certified senior reactor operators to the TSC coordinator assistant, TSC communicator, and TSC information specialist positions. This use of senior reactor operators contributed significantly to the efficiency of communications between the TSC and the other emergency response facilities, prioritization of response team efforts, and overall management of activities within the TSC. The inspectors noted improved performance of the TSC staff from previous training drills. Specifically, the improved coordination of TSC activities by the TSC coordinator, the radiation protection manager, and the technical manager was noteworth m o

.

b-17- Conclusions Station emergercy response organization performance in the TSC during the first 1999 quarterly emergency preparedness training drill showed considerable improvement from previously obseWed drills. Communications between the emergency response facilities and prioritization of response teams was significantly better than past drills. The addition of engineers to the TSC staff and the increased use of licensed and certified i senior reactor operatore were strength V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 25,1999. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie i

c

,

~;.

.

ATTACHMENT PARTIAL LIST OF PERSONS CONTACTED Licensee C. Bottomille' r, Superintendent, Plant Licensing C. Brooks, Licensing Specialist, Plant Licensing

' B. Carroll, Superintendent, Operations

- D. Cupstid, Manager, Operations Technical Support J. Czaika, Nuclear Specialist B. Edwards, Mechanical Maintenance Superintendent, Plant Maintenance C. Elisaesser, Manager, Performance and System Engineering C. Gunn, Administrated Specialist, Nuclear Safety and Regulatory Affairs F. Guynn, Emergency Planner C. Holifield, Licensing Engineer, Plant Licensing

- K. Hughey, Director, Nuclear Safety and Regulatory Affairs D. Janecek, Director, Training

'C. Lambert, Director, Design Engineering

' J. Roberts, Director, Quality Programs -

C. Townsend, Operations Coordinator J. Venable, General Manager, Plant Operations R. Wilson, Superintendent, Radiation Control NRS P. Sekerak, NRR Project Manager INSPECTION PROCEDURES USED 37551 Onsite Engineering 61726 Surveillance Observations 62707 ' Maintenance Olnervation 71707 Plant Operations 71750 Plant Support Activities

!

I l*

!:

i'

i 2-ITEMS OPENED. CLOSED. AND DISCUSSED l Opened

!

50-416/9904-01 NCV Replace Valve 1P41F299A, Train A SSW Relief Valve, Tailpipe (Section M1.2)

50-416/9904-02 NCV Control of scaffolding (Section E2.1)

50-416/9904-03 NCV Trains A and B BSW minor through-wall pipe leakage

-

(Section E2.2)

Closed 50-416/9904-01 NCV Replace Valve 1P41F299A, Train A SSW Relief Valve, Tailpipe (Section M1.2)

50-416/9904-02. NCV Control of Scaffolding (Section E2.1)

50-416/9904-03 NCV Trains A and B SSW Minor Through-Wall Pipe Leakage (Section E2.2)

!

l i

i

!

l

'

v p:

c:

. . .

- LIST OF ACRONYMS USED ASME American Society of Mechanical Engineers CFR Code of Federal Regulations CR condition report ER emergency response organization ESF engineered safety f(ature -

.GL generic letter LCO limiting condition for operation NCV- r:oncited violation RWCU reactor water cleanup SR surveillance requirement SSW standby service water TRM Technical Requirements Manual TS Technical Specification TSC technical support center UFSAR . Updated Final Safety Analysis Report I