ML13060A225

Watts Bar, Unit 2 - Response to Request for Additional Information Group 7 Regarding Fire Protection Report, (TAC No. ME3091) [Public Version]

ML13060A225
Person / Time
Site:	Watts Bar
Issue date:	09/30/2011
From:	Stinson D Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC ME3091
Download: ML13060A225 (145)

Text

{{#Wiki_filter:Tennessee Valley Authority, Post Office Box 2000, Spring City, Tennessee 37381-2000September 30, 201110 CFR 50.4U.S. Nuclear Regulatory CommissionATTN: Document Control DeskWashington, D.C. 20555-0001Subject:Watts Bar Nuclear Plant, Unit 2NRC Docket No. 50-391WATTS BAR NUCLEAR PLANT (WBN) UNIT 2 -REQUEST FORADDITIONAL INFORMATION (RAI) GROUP 7 REGARDING "FIREPROTECTION REPORT" (TAC NO. ME3091)NRC letter to TVA dated September 14, 2011, "Watts Bar Nuclear Plant, Unit 2 -Request for Additional Information Regarding Final Safety Analysis ReportAmendment Related to Section 9.5.1 'Fire Protection System' Group 7(TAC NO. ME3091)"Reference:The purpose of this letter is to respond to NRC's Group 7 RAIs pertaining to WBN Unit 1/Unit 2Fire Protection Report contained in the referenced letter. This letter also responds to: (1) NRCquestions received during a public meeting held in Rockville, Maryland, on August 31, 2011;(2) an email from NRC (Justin Poole, NRR) received on September 20, 2011; and (3) NRC'srequest for documentation that supports WBN's current audit frequency of the Fire ProtectionProgram based on the results of past audits that was received during a teleconferenceconducted on September 12, 2011.Enclosure 1 to this letter provides TVA's responses to NRC's requests/questions. Enclosure 2provides the new Regulatory Commitments contained in this letter.If you have any questions, please contact Gordon Arent at (423) 365-2004.I declare under the penalty of perjury that the foregoing is true and correct. Executed on the30th day of September, 2011.Respectfully,David StinsonWatts Bar Unit 2 Vice President. U.S. Nuclear Regulatory CommissionPage 2September 30, 2011Enclosures:1. Response to NRC's Request for Information Regarding "Fire Protection Report"2. Regulatory Commitmentscc (Enclosures):U. S. Nuclear Regulatory CommissionRegion IIMarquis One Tower245 Peachtree Center Ave., NE Suite 1200Atlanta, Georgia 30303-1257NRC Resident Inspector Unit 2Watts Bar Nuclear Plant1260 Nuclear Plant RoadSpring City, Tennessee 37381 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"Reference: NRC letter to TVA dated September 14, 2011, "Watts Bar Nuclear Plant, Unit 2 -Request for Additional Information Regarding Final Safety Analysis ReportAmendment Related to Section 9.5.1 'Fire Protection System,' Group 7(TAC NO. ME3091)"The following provides TVA's response to the referenced NRC requests for additionalinformation (RAI) pertaining to the WBN Unit 2 Fire Protection Report (FPR). This enclosureprovides TVA's responses to: (1) NRC questions received during a public meeting held inRockville, Maryland, on August 31, 2011; (2) an email from NRC [Justin Poole, NRR) receivedon September 20, 2011; and (3) NRC's request for documentation that supports WBN's currentaudit frequency of the Fire Protection Program based on the results of past audits that wasreceived during a teleconference conducted on September 12, 2011.NRC's numbering system will be referenced to identify each question. Some NRC questionshave been subdivided for clarity of response.1. NRC Question (RAI FPR General-7)The reviewers have found that not all RAI responses have been successfully incorporatedinto the FPR. Two examples:1. The TVA response to RAI 11-8 (in the March 16, 2011, TVA letter) states, in part:However, WBN does not reduce a fire watch from continuous to hourly rovingin areas containing fire safe shutdown equipment for a unit in Modes 1 to 4,inclusive. WBN does reduce a fire watch from continuous to hourly roving forareas where a fire would impact the units in Modes 5, 6, and core empty.The FPR will be revised to clarify that this reduction only applies to areas andequipment affecting the unit in Modes 5, 6, and core empty and does notapply to areas that affect the other unit while in Modes I to 4 inclusive.However, the FPR contains numerous locations where this change has not been made.Some examples:When either unit is in Modes 5 and 6 or core empty, roving fire watches maybe used in lieu of continuous fire watches when approved by the FireProtection Supervisor (or designee). Locations where a continuous fire watchwould be required in Modes 1 -4 may be combined and patrolled by a rovingfire watch. [pg. 11-47]NOTE 4: With either unit in Modes 5, 6, or core empty, locations where acontinuous fire watch would be required may be combined and patrolled by aroving fire watch when approved by the Fire Protection Supervisor (ordesignee). [pg. 11-52]E1-1 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"NOTE 1: With either unit in Modes 5, 6, or core empty, locations where acontinuous fire watch would be required may be combined and patrolled by aroving fire watch when approved by the Fire Protection Supervisor (ordesignee). [pg. 11-53]Other instances of this condition exist in the FPR.2. The TVA response to RAI FPR Ill-13 (in the May 6, 2011, TVA letter states, in part:Part III, Section 4.7 is incorrect. The third paragraph should read: "The CCS[component cooling water system] system provides cooling for the following safeshutdown equipment per unit." (emphasis added)However, Part Ill, Section 4.7, of the FPR reads: The CCS system provides cooling forthe following safe shutdown equipment per Unit 1: (emphasis added)To resolve the problems with RAI response incorporation:0 [1] Correct the FPR to bring it into alignment with these RAI responses in all instances.0 [2] Provide assurance that other, similar deficiencies with respect to modifying the FPRto align with other RAI responses have been found and corrected.This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:[1] For example 1 above addressing fire watches:The FPR, Part II, Section 13.0.A will be revised to read as follows:Section 13.0.A, beginning-The locations that a continuous fire watch is required are based on plantconditions existing at the time the fire watch is in place and modified as needed.Continuous fire watches will be restricted to patrolling one fire area except asnoted below.Continuous fire watches are only required when the affected unit is in Modes 1(Power Operation) to 4 (Hot Shutdown), inclusive. A "roving" fire watch will coverthe designated areas on an hourly basis in areas where only the unit in Modes 5,* 6, or core empty would be affected by a fire. If a fire in the area could affect bothunits then a continuous fire watch is required.Section 13.A, last paragraph-Situations may arise in which. the system or equipment cannot be restored withinthe time specified by the Fire Protection Systems and Features OperatingE11-2 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"Requirements (Section 14.0). In such cases, an augmented compensatory actionwill be taken to ensure that a continuous fire watch does not go to different fireareas. The 15 minute requirements will still apply, but the continuous fire watchmust remain within the same fire area. This augmented compensatory action isnot required when only the unit in Modes 5, 6, or core empty could be affected bya postulated fire.For other places in the FPR that refer to the change from continuous to hourly roving inModes 5, 6, and core empty, the associated statement will be revised to state:With a unit in Modes 5, 6, or core empty, locations where a continuous fire watchwould be required may be combined and patrolled by a roving fire watch whenapproved by the Fire Protection Supervisor (or designee) if the location onlyaffects the unit in Modes 5, 6, or core empty.This change will be made to:13.0.814.1, Note 414.2, Note 114.3, Note 314.4, Note 314.8, NoteIn other locations in the FPR, the following statement will be used:When a unit is in Modes 5 (Cold Shutdown), 6 (Refueling), or core empty, thelocations where a continuous fire watch would be required may be combined andpatrolled by one or more roving fire watch(es) provided the area only affects theunit in Modes 5, 6, or core empty. While a unit is in cold shutdown or refueling,there are fewer systems needed for maintaining cold shutdown and more peoplepresent that could detect and report a fire (General Employee Training includeshow to report a fire). Roving fire watches provide an adequate level of coveragefor these systems by ensuring that potential fire hazards are detected andcorrected in a timely manner to prevent fires from occurring, or if a fire were tooccur, ensuring that timely action is taken.This change will be made to the appropriate paragraphs in the following bases sections:B.14.1B.14.2.1B.14.3B.14.4B.14.8E1-3 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"For example 2 above addressing CCS:For example 2 above addressing Part III, Section 4.7 and the CCS system:"The CCS system provides cooling for the following safe shutdown equipment perunit."An extent of condition was performed and no other instances of this were found. Thecorrections identified in this subsection will be submitted in the next FPR.[2] A review of the FPR has been performed to identify and correct similar deficiencies thatoccurred when modifying the FPR to align with past RAI responses. The deficienciesthat were identified during this review will be submitted in the next FPR. A summarytable of the identified deficiencies is included in Attachment 1.2, NRC Question (RAI FPR General-8)The reviewers continue to identify problems with Information Quality Control and otherinconsistencies in the FPR. Two examples:[1] An important explanatory sentence was deleted from Part VI Section 3.26.1 [pg. VI-437].With the change, this section now reads:Deviations: The justification for intervening combustibles such as insulationon cables in trays and Thermo-Lag is documented in Part VII, Section 2.4.a. Wide range steam generator levelb. Tank level for the condensate storage tank (CST) and refueling waterstorage tank (RWST).c. Reactor Coolant System (RCS) cold leg temperature (TJ).The justifications are documented in Part VII, Section 2. 1.[2] A change was made to Part VI, Section 3.22.2.1 [pg. VI-363] to add a protected cable toanalysis volume AV-041M. However, summary Table I-I was not updated to reflect thischange.[3] Perform an information quality and consistency review on the FPR and incorporate theresults.TVA Response:[1] Part VI Section 3.26.1 will be revised to read:Deviations: The following instrumentation has not been provided in the AuxiliaryControl Room:E1-4 ENCLOSURE1IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"a. Wide range steam generator levelb. Tank level for the condensate storage tank (CST) and refueling water storagetank (RWST).c. RCS cold leg temperature (Tc).The justifications are documented in Part VII, Section 2.1.The justification for intervening combustibles such as insulation on cables in traysand Thermo-Lag is documented in Part VII, Section 2.4.[2] Part I, Table I-1 will be revised to show that Fire Area 16, Room 757.0-A5 contains firewrap.This change will make Part VI, section 3.22.2.1 consistent with Table I-1 for analysisvolume AV-041 M. Table I-1 will be re-reviewed as part of the as-constructed FPR toensure consistency with the remainder of the FPR.The corrections identified in the FPR Part VI, Section 3.26.1, subsection [1] and Part I, TableI-1, subsection [2] will be submitted in the next FPR.[3] As previously stated in letter item No. 1, a review of the FPR has been performed toidentify and correct similar deficiencies that occurred when modifying the FPR to alignwith past RAI responses. The deficiencies that were identified during this review will besubmitted in the next FPR. A summary table of the identified deficiencies is included asAttachment 1.3. NRC Question (RAI FPR 1-3)In the revised summary Table I-1, a number of rooms are indicated as having both requiredmanual actions (and repairs) and no fire safe shutdown (FSSD) equipment installed.Examples include: 713.0-A 10, 713.0-A 17, and 737.0-A 10.[1] Provide a technical justification for this configuration or correct the Table. [2] Provideassurance that other inconsistencies between the summary Table and the balance of theFPR have been identified and corrected.This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:[1] A review of the safe shutdown analysis determined that the three rooms 713.0-Al 0,713.0-A17 and 737.0-A10 do not have any FSSD equipment or cables in them and thereare no operator manual actions (OMAs) or repairs required for a fire in the rooms.Room 713.0-Al0 is part of analyses volumes AV-024 and AV-025C which also includesfire zones 713.0-A1A4 and 713.0-AlAN. Fire zones 713.0-A1A4 and 713.0-AlANcontain FSSD components; and a fire in either of these zones require OMAs and/orE1-5 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"repairs, but 713.0-Al0 does not contain components required for FSSD; therefore, a firein the room will not result in an OMA/repair, nor are there any OMAs/repairs that arerequired to be performed in this room due to a fire elsewhere.Room 713.0-A17 is part of analyses volumes AV-025C and AV-026 which also includesfire zones 713.0-A1B and 713.0-AlBN. Fire zones 713.0-A1B and 713.0-AlBN containFSSD components and a fire in either of these zones require OMAs and/or repairs, but713.0-A17 does not contain components required for FSSD; therefore, a fire in the roomwill not result in an OMA/repair, nor are there any OMAs/repairs required to be performedin this room due to a fire elsewhere.Room 737.0-Al0 is part of analysis volume AV-1 13 which consists of rooms 729.0-Al1and 737.0-AlO. Room 729.0-Al1 contains FSSD components, but does not contain anysignificant ignition sources nor quantity of combustibles that would damage any FSSDcomponents; however, it is assumed that a postulated fire in the room could damagecomponents and require OMA/repairs. Room 737.0-AlO does not contain any FSSD;therefore, no fire in the room requires an OMA/repair nor are there any OMAs/repairsrequired to be performed in the room due to a fire elsewhere.Table 1-1 will be corrected to reflect that no OMAs or repairs are required for a fire inrooms 713.0-Al0, 713.0-A17 and 737.0-A1O and will be submitted in the next FPR.[2] As previously stated in letter item No. 1, a review of the FPR has been conducted forconsistency between sections. Identified discrepancies have been corrected and will beincluded in the next FPR submittal. It should be noted that Table 1-1 is subject tochanges as modifications are completed. The as-constructed submittal of the FPR willdocument the plant configuration at the time of Unit 2 fuel load.4. NRC Question (RAI FPR 11-37.1.1)The TVA response to RAI FPR 11-37.1, in the August 5, 2011, TVA letter indicates that theFPR would be modified to provide requirements for inaccessible areas outside ofcontainment.However Part II, Section 14.1.2.b of the FPR is not clear that it applies only to inaccessibleareas. Modify the text to indicate this, or explain the difference in applicability between14.1.2.b and 14.1.1.This RAI may involve an update to the FPR to incorporate the response to the RAI..TVA Response:FPR, Part II, Section 14.1.2.b will be revised to specify that the section applies only toinaccessible areas outside of containment, as defined by the FPR, Part II, Section 5.0.Wording similar to the following will be used:El -6 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"With any of the required Function A fire detectors in a fire detection zone identified onTable 14.1 inoperable in an inaccessible area outside containment, within eight hours,restore the inoperable equipment -OR- establish a roving fire watch once per 8-hours.The basis for this section was previously revised to state "inaccessible area outsidecontainment" in the FPR that was submitted in TVA's letter dated August 15, 2011.5. NRC Question (RAI FPR 11-44.1)The TVA response to RAI FPR 11-44, in the August 5, 2011, TVA letter, provides the basisfor B. 14.2. f, specifically, "The TIR [Testing and Inspection Requirements] bases, B. 14.2. f,calls for this testing to compare the friction loss characteristics of the piping to previoustests."Additionally, B. 14.2.f states, "Any flow test that results in unacceptable deterioration ofavailable flow and pressure shall be fully investigated."* [1] Provide the technical justification that demonstrates that, since the licensing of Unit 1,there has not been an "unacceptable degradation" in friction loss characteristics basedon the testing described by B. 14.2.f.0 [2] Provide a summary of the representative testing and discussion of how the resultssince licensing of Unit I demonstrate that the flow characteristics of the piping systemare capable of providing for flows representative of those expected during a fire.0 [3] Describe the criteria used in making the determination of "unacceptabledeterioration."TVA Response:[1] The response to question number 10, RAI FPR VII-2.6.1, provides a summary of thereview of the testing performed since licensing of Unit 1 and concludes that the systemhas not experienced an unacceptable degradation due to friction loss characteristics.[2] The testing performs the following:1. Removes the isolatable raw service water (RSW) loads from the system.2. Starts two electric fire pumps (e.g., one from one unit and train and another from theother unit and other train).3. Provides a flow equal to the non-isolatable RSW loads to ensure this load is on thesystem during testing. If the non-isolatable RSW load begins using water during thetest, it adds an element of conservatism to the test results.4. Performs a flow test of specific points on the system. These are the same points foreach test. The test suggests the placement location of the instrumentation to attemptto have consistent data from year to year.E1-7 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"The System Description, N3-26-4002, "High Pressure Fire Protection System,"summarizes the anticipated system capability based on piping condition using raw water.The response to Letter Item # 6, RAI FPR 11-44.2, provides a discussion of how theUnit 1 testing demonstrates that the system is capable of providing flows representativeof those expected during a fire..[3] The engineering calculations, as summarized in the System Description, N3-26-4002,"High Pressure Fire Protection System," states that for the 40-year life of WBN, the hosestations on the roof of the Auxiliary Building will not be able to achieve a flow of 500GPM at a residual pressure of 65 PSIG. This calculation is based on piping degradationthat would happen after 40 years. It is expected that the piping conditions after 40 yearsof use will result in a coefficient of roughness of C=55 and a reduced pipe diameter of0.8 inches. So based on:1. the piping being installed for over 30 years,2. the system testing is verifying the expected 40-year life of plant calculations, and3. the hose stations of concern, in accordance with the System Description, havepassed the acceptance criteria. (Note: The Auxiliary Building roof hose station hasbeen re-tested from the last performance when it was discovered the measurementand test equipment was out of calibration. This re-test passed the acceptancecriteria, but a corrective action document, Service Request 434337, was initiated toaddress the anticipated future failure.)It is evident there has not been any unacceptable deterioration of the system sinceUnit 1 licensing, only anticipated system changes.There is no formal definition of "unacceptable deterioration." As long as the system isstill capable to perform its intended function and still exhibits the ability to continue toperform its intended function, "unacceptable deterioration" is based on engineeringjudgment.6. NRC Question (RAI FPR 11-44.2)The TVA response to RAI FPR 11-44, in the August 5, 2011, letter, states: "The hose stationflow paths from the main header are hydraulically separate from the main header tosprinkler flow paths and thus the hose stations do not impose hydraulic loads on thesprinkler paths."Page VIII-40 of the FPR states: "Adequate fire fighting water requirements are considered tobe the calculated flow and pressure to provide flow and pressure to meet suppressionsystem design basis, including hose stream allowance and unisolated RSW [raw servicewater] loads."The RAI response is inconsistent with the FPR, since the FPR states that the hydrauliccalculations consider not only the hose station loads, but also the unisolated RSW loads.Since the hose and RSW loads are considered in the calculation, they also need to beconsidered in the testing.E1-8 ENCLOSUREIResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"Describe how the flow tests performed at WBN account for the additional flow for the firehoses and the unisolated RSW loads.TVA Response:The capability to meet the total flow requirements is established by the flow calculationrather than the flow test. The calculation addresses the total flow to the hydrants, sprinklers,and/or hose stations and unisolated raw service water (RSW) loads. The calculation isbased on the flow expected durinla fire from sprinkler heads over a 1500 sq. ft. area, whichresults in a total flow just under 500 gpm for the worst case location in the Auxiliary Building.The calculation also assumes a 500 gpm hose allowance at the sprinkler system flowcontrol valve and 105 gpm of unisolated RSW flow. The calculation evaluates the variousareas/elevations of the buildings to demonstrate the capability to meet the total flowrequirements for a single fire in any area/elevation containing FSSD equipment.The purpose of the hydraulic flow test is not to demonstrate the capability to meet the totalflow requirements but instead to trend the system for any unexpected changes in the supplypiping. The calculation established the worst case locations for each type of load within thesystems and determined the locations at which the flow in the future is most likely to dropbelow the acceptable flow rate due to system degradation (i.e., corrosion). The historicalflow test results along with the most recent test data are then used to trend the flow in theserepresentative flow paths so that TVA can predict the need to correct degradation before theability to mitigate fires is impacted. Since the purpose of the testing is to trend degradationin the individual flow paths, it is not necessary to simulate the total flow (i.e., sprinklers plusfire hose flow from hose stations or hydrants) during the test.As stated in the referenced RAI response, the system flow is supplied from large mainheaders. The total flow through the main headers is relatively small and is not expected tobe a limiting factor at anytime during plant life. The flow path(s) for the main header(s) tothe sprinklers is separate from the flow path for the main header(s) to the hose stations andthus it is not necessary to test the sprinkler flow paths at the same time as the hose stationflow paths are tested. The flow test does include a 105 gpm flow to simulated RSW loads.The simulation of hose station flow and/or unisolated RSW loads is not a requirement asdiscussed above; however, the concern of RSW loads on the fire protection water supplyduring a fire resulted in including these loads during testing. This unisolated RSW demandis 105 gpm, which is insignificant since two 1590 gpm pumps are supplying the system atthis time. All sections, except for the one section that tests the diesel fire pump supplypiping, of the hydraulic testing at WBN account for the unisolated RSW loads by setting up asurrogate flow equivalent to the unisolated RSW loads at a fire hydrant at a location which isrelatively remote from a hydraulic standpoint from the water supply (two electric fire pumps).Thus, if any of the unisolated RSW loads do place a demand on the system during testing,this demand is in addition to the surrogate demand, and adds an element of conservatism tothe test.E1-9 ENCLOSURE1IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"7. NRC Question (RAI FPR 11-46)Part II, "Fire Pump Inoperability and Compensatory Measures" Table of the FPR, appears tobe inconsistent with the configuration of the plant.Based on the Part II, Section 12.1, there are four electric motor driven fire pumps (EMFPs)and there is one diesel fire pump (DFP).Examples:* Column 14.2.2 in the Table shows two EMFPs, one operable, one inoperable. What isthe presumed status of the other two EMFPs?" Table column 14.2.3, states one DFP operable and two inoperable, whereas 14.2.3 ofthe text stays, "With no electric driven pumps operable. .."Explain the discrepancy between the number of EMFPs in the Table versus the otherinformation provided in the FPR.This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:TVA agrees that the duplication of the Operating Requirements (OR) in the Section 14.2 textand table could be confusing and could lead to errors. Thus, since this is a duplication ofinformation, the table in the FPR, Part II, Section 14.2 will be removed. The removal of thistable addresses the concern as to the discrepancy between the number of pumps and relieson the descriptive paragraphs in Section 14.2 to address the number of pumps required.TVA also agrees there may be confusion due to the fact that there are four electric drivenpumps with only two of them required for fire protection operability purposes. In order toaddress this possible confusion, the following paragraph will be added after the firstparagraph in Part II, Section 12.1:The WBN fire protection system has four electric driven pumps and one diesel drivenpump. As defined in Section 14.2.a below, fire protection Operability is based on onlytwo of the four electric pumps and the diesel driven pump. The other two electricdriven pumps are considered spares for fire protection purposes. The four electricpumps and associated main piping headers are ASME Section III, seismic class Iavailable for supplying auxiliary feedwater during a design basis event (i.e., FloodMode). During Flood Mode two electric pumps are aligned to each train header.Details of the Flood Mode are documented in several places in the FSAR such asSection 2.4.14.2, "Plant Operation During Floods Above Grade." The ASME andseismic requirements are beyond the requirements of the NFPA Code and are notrequired for fire protection purposes.The changes contained in this item will be submitted in the next FPR.El-10 ENCLOSURE1IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"8. NRC Question (RAI FPR 11-47)A change was made in Part II of the FPR to delete TIR 14. 1O.n.Explain this change and provide a technical justification for the deletion of TIR 14. 1O.n.TVA Response:Testing and Inspection Requirement (TIR) 14.10.n was erroneously removed. The testing isperformed by a Surveillance Instruction (SI) with references to Technical Specification (TS)Surveillance Requirements (SR); however, the SI did not properly reference the TIR. Siswere required to reference the test requirements being implemented, and the omission ofthe TIR in the SI was an error. The lack of a reference in the TS SR resulted in theassumption the TIR was not needed. To correct the procedures, a corrective actiondocument, Service Request 433266, has been initiated.Thus the reference to the TIR will be added to the SI and the TIR will be added back to theFPR by adding the following:ITEM TYPE OF FREQUENCY TESTING/INSPECTION NOTESNO. SYSTEM/COMPONENT REQUIREMENT (TIR)14.10.n 1-FCV-3-116A 1-HS-3- 18 months Verify with the hand switch in116ANC 1-XS-3-116A 1- P-Auto and the transferFCV-3-116B 1-HS-3- switch placed in the Aux116B/C 1-XS-3-116B 1- position that the FCV willFCV-3-126A 1-HS-3- automatically open on low126A/C 1-XS-3-126A 1- level in the CST.FCV-3-126B 1-HS-3-126B/C 1-XS-3-126B2-FCV-3-116A 2-HS-3-116A/C 2-XS-3-116A 2-FCV-3-116B 2-HS-3-116B/C 2-XS-3-116B 2-FCV-3-126A 2-HS-3-126A/C 2-XS-3-126A 2-FCV-3-126B 2-HS-3-126B/C 2-XS-3-126BIn addition, the following bases will be added to the FPR, Part II for this TIR:B.14.10.n TIR 14.10.n verifies every 18 months the remote switches for P-Auto operatecorrectly when the associated transfer switch is in AUX. This testing isconsistent with the surveillance requirements for these switches (referenceTechnical Specification SR3.3.2, 3.3.3, 3.3.4, and 3.7.5)The changes contained in this item will be submitted in the next FPR.El-11 ENCLOSUREIResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"9. NRC Question (RAI FPR V-13. 1)TVA's response to RAI FPR V-13 (in the August 5, 2011, TVA letter) indicates that there areno differences between the t=O definition for fires where the reactor trip is performed fromthe main control room and where an automatic reactor trip is caused by the fire.However, the FPR still defines t=O as the time when the reactor is tripped from the MainControl Room.Revise the FPR to reflect the definition of t=O as described in the TVA RAI response.Additionally, the reviewers noted that TVA also provided additional information referencingAppendix E of Nuclear Energy Institute document NEI-O0-01, Revision 2. This Appendixhas not been endorsed by the NRC.This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:Part V, Section 2.2.2 of the FPR will be revised and submitted in the next FPR. It will readas follows:2.2.2 Operator Locations Prior to Initiating Manual Actions and t=O DefinitionFor the purposes of developing the safe shutdown procedures, all operatorsperforming manual actions are dispatched from the main control room for fires inmost plant locations, or from the Auxiliary Control Room for Control Building fires.The basis for dispatch locations is that the operators must obtain the operator-specific safe shutdown procedures from these locations.There are two scenarios for determining the time at which a reactor is tripped.One scenario is that the fire develops to a point that it damages equipment thatwill initiate an automatic reactor trip. The second scenario is that the MCR stafftrips the reactor after assessing the fire and determining that tripping the reactor isnecessary. The time at which the reactor is tripped is defined as t=0.There are no differences in the actions or timing requirements following t=0 for thetwo scenarios. This is because a fire that could grow to the point of causingdamage that results in an automatic reactor trip would have been assessed byplant personnel as a challenging fire with the potential to damage structures,systems, or components necessary for safe shutdown. The decision to trip thereactor manually would have been reached prior to or about the same time as firedamage actually causing automatic reactor trip.Industry test data indicates that fire induced circuit failures will not occurimmediately upon exposing cables to fire effects. Damage from an exposure fireto safe shutdown components or circuits is not expected to occur for at least 10minutes after confirmation by plant personnel.El-12 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"Fire locations subject to high energy rapidly developing fires (e.g., electrical boardrooms and transformer rooms) do not contain cables or equipment whose failurecould initiate automatic reactor trip. The control room is alerted of a fire in its earlystages either by the fire detection system or as a result of visual observation byplant personnel. The operator's initial response includes:a. Initiate plant fire alarmsb. Notify Fire Brigadec. Ensure fire pumps are runningd. Announce Incident Command Post location over PA systeme. Assemble AUOs in the control room if the confirmed fire is in the AuxiliaryBuilding or either Reactor Building (AUOs assemble at the Auxiliary ControlRoom if the fire is in the Control Building).The time requirements for completion of manual operator actions are based ondefining the initiating time t = 0 as the time when the reactor is tripped. Thisdefinition of the analytical t = 0 is appropriate because the manual actions arerequired to stabilize the plant or maintain it in a stable condition after reactor trip.The manual actions are not required to maintain the operating status of plantequipment prior to tripping the reactor because the reactor is considered to be in astable operating condition prior to reactor trip. Once a trip is initiated, eitherautomatically or manually, the preventive OMAs are performed to preventspurious equipment operation and to ensure safe shutdown can be accomplished.Nearly all of the actions are preventive rather than reactive; they are performedper procedure rather than using process instrumentation or other indication todiagnose a need for the action.There are very few situations where reactive action must be taken based upon firedamage to equipment or cables rather than trip initiation. In these situations thenormal plant system operating procedure provides the reactive response while theFSSD procedure is preventive (action taken before fire damage causes a need forthe action). For example:1. Electrical power distribution board fire -The normal response and the safeshutdown action are the same; de-energize the board prior to extinguishingthe fire.2. Spurious start of a containment air return fan. The fan must be stopped.Existing system operating procedures require securing the fan (opening thebreaker) which is the same action required for FSSD.The reference to Appendix E of NEI-00-01, Revision 2 was only for additionalinformation and will not be included in the FPR.10. NRC Question (RAI FPR VII-2.6.1)RAI FPR VII-2. 6 requests, in part, that TVA: "Provide a detailed summary of the trendinginformation for each of the monitored hose stations."El-13 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"The TVA response to RAI FPR VII-2.6, in the August 5, 2011, TVA letter, directs the readerto the response to RAI FPR VII-2.3 for this information. However, examination of theresponse to RAI FPR VII-2. 3 shows that it does not contain information on trending. Theresponse to RAI FPR VII-2. 2 does provide some discussion of trending, but does notprovide the detailed discussion that RAI FPR VII-2. 6 was requesting.* Provide a detailed summary of the trending results for each of the eight trending pointsidentified in parts 1 and 2 of the TVA response to RAI FPR VII-2.2 from Unit I licensingto the present.TVA Response:In TVA's July 22, 2011 response to the round 6 questions, the eight points discussed are:Location ValvesAuxiliary Bldg Roof 0-ISV-26-654 & -655DGB Roof 0-ISV-26-565 & -566IPS 0-ISV-26-1710 & -1711Auxiliary Bldg Sprinkler System 0-FCV-26-143 and -322Auxiliary Bldg Sprinkler System 0-FCV-26-151 and -326Control Building Sprinkler System 0-FCV-26-211DGB Hydrant 0-HYD-26-819DGB Sprinkler System 0-FCV-26-167A summary of the trending is:General -This review does not show an adverse trend in relation to the calculatedperformance of this system. The last performance of these points tested does not indicate aneed for more frequent testing with the exception of the Auxiliary Building Roof hosestations.The plotting of the test data for each test point on a single semi-log Microsoft Excel graphdoes show variations, as expected. These variations are due to items such as the set pointof the system pressure control valve, tolerance of the measurement and test equipment(M&TE) used, different personnel reading gauges, piping replacement, etc. The left handpoint on each curve is established by measuring the static pressure at each location with thesupply valve to that path closed (i.e., no flow condition). In this configuration, the system issupplying the simulated 105 gpm of un-isolated RSW flow but the system is basically in a noflow condition since the 105 gpm is insignificant compared to the system flow capability.The pressure at the test location is a direct result of the setpoint of the pressure controlvalve (PCV) at the Intake Pumping Station. Since the parameter of concern for the test isthe change in pressure in the flowing condition versus the no flow condition, it is not criticalthat the PCV is at the same setpoint pressure for each test. This difference in PCV setpointis evidenced by the static pressure in 1995 (i.e., 103 psig) versus the static pressure in 1996(i.e, 130 psig).E1-14 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"The flow path is then opened. The flow rate through the path is measured along with theresidual static pressure in the line. The resulting flow rate and residual pressure point forboth the no flow and flowing condition are then plotted as shown on the attached plot. TheHazen-Williams equation for friction losses due to friction is:hLf= 0.2083 (100/C)185 * (Q185/(d-2Ad)48655)where: hLf = Friction lossC = Surface characteristic roughness coefficientd = inside pipe diameterAd= Reduction of inside pipe diameter due to corrosion product buildupQ = Flow rateA semi-log plot of the flow rate using a log axis to the 1.85 power would yield a straight lineindicative of the friction induced pressure drop. It is noted that the attached semi-log plotuses a power of 2 instead of 1.85 due to the use of an Excel spreadsheet to create theprovided figure. This plot is deemed to be sufficient close for illustrative purposes.The parameter of concern for the high pressure fire protection (HPFP) system test is thechange in pressure drop due to corrosion induced friction (i.e., hLf). Changes in frictioninduced pressure drop would be evidenced by a change in the slope of the line on theattached plot. As can be seen, the lines are basically parallel thus indicating very littlechange in pressure drop versus time.An example of the test data is presented in graphical format in Attachment 2.The replacement of the majority of the buried 12 inch B-train header in 2005 did not have anapparent affect on these points. What may be a more prevalent factor in the up and downvariations of the graphed slopes is more likely the replacement of the Auxiliary. Buildinginterior loop piping. This interior piping has had different sections replaced since 1995 aspin-hole leaks developed. This piping is 6 and 8 inch and could have a greater effect on thetesting considering the reduced roughness and increased internal diameter that the newpiping would provide.The following summarizes the results for each station:Auxiliary Bldgq Roof Hose Stations 0-ISV-26-654 & -655Plotting of the data collected since 1995 shows the curves for the combined flow of bothhose stations to vary for the different tests. In the middle years testing, the curves tended tohave less slope indicating a positive trend which is possibly due to replacement of differentsegments of header piping in the Auxiliary Building. This flow point is one that failed thetest's acceptance criteria, apparently due to an out of tolerance M&TE in 2010. A retest wasconducted September 2011 and the point passed the acceptance criteria, but due toconcerns about failure at the next performance, a corrective action document, SR 434337,has been initiated.El-15 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regardina "Fire Protection Report"DGB Roof Hose Stations 0-ISV-26-565 & -566Plotting of the data collected since 1995 shows the combined flow of both hose stations hasshown a very steady trend based line slope. The latest test data indicates a positive trend.The failed M&TE was used on this test with no apparent affect.IPS Hose Stations 0-ISV-26-1710 & -1711Plotting of the data collected since 1995 shows the combined flow of both hose stations hasshown a consistent trend. There has been an improvement since the 1995 original test butthis test was skewed due to excessive flow during the testing resulting in an elevatedReynolds number and turbulent flow.Auxiliary Bldg Sprinkler System 0-FCV-26-143 and -322The trend has been fairly consistent since original testing. There is slight variation in thedifferent slopes, but the 1995 and 2010 line slopes are very similar.Auxiliary Bldg Sprinkler System 0-FCV-26-151 and -326The trend has been fairly consistent since original testing. There is slight negative trendwhen comparing the 1995 and 2010 line slopes, but both match slopes for other years andappear to be within normal variation.Control Building Sprinkler System 0-FCV-26-211The trend has been fairly consistent since original testing. The slope for the 1995, 2001,and 2010 appear to match. The other years are within normal variation.DGB Hydrant 0-HYD-26-819The trend of the slope of these lines for these test points is very consistent, which is asexpected since the supply piping for this hydrant is cement lined ductile iron pipe.DGB Sprinkler System 0-FCV-26-167The trend of the slope of these lines varies in the same range as other comparisons. Theslope of the 1995 and 2010 performance is close with the 2010 indicating a slightimprovement which is probably caused by M&TE tolerance.El-16 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"11. NRC Question (RAI FPR VII-2. 7)During the July 12, 2011, public meeting, it was noted that there are pressure/flow testsrequired for American Society of Mechanical Engineers (ASME) Class 3 piping per ASMEcode. At the meeting neither TVA nor the NRC was able to determine in detail what thesetests were, or whether they were being performed at the Watts Bar site.Provide a summary of the testing performed on the high pressure fire protection Train Aand Train B safety related headers because of their classification as ASME Class 3piping. The summary should include, at a minimum, a description of each test, the testfrequency, and acceptance criteria.TVA Response:The buried Train A and Train B safety-related headers are classified as ASME Class 3piping. This piping was constructed to ASME Section III and maintained to ASMESection Xl as Class 3, not because they are used for an accident, but because they areused for the design bases event of flood mode at WBN to supply auxiliary feedwater. Theseheaders do not meet the criteria to be part of the System Pressure Test Program (SPT)based on the criteria from ASME, Section XI, IWD-1210 which states:The examination requirements of this Subsection shall apply to pressure retainingcomponents and their welded attachments on Class 3 systems in support of thefollowing functions:(a) reactor shutdown(b) emergency core cooling(c) containment heat removal(d) atmosphere cleanup(e) reactor residual heat removal(f) residual heat removal from spent fuel storage poolThis piping is not part of the reactor residual heat removal system, but is a part of theemergency feedwater system, in accordance with American National Standard N18.2-1973,Section 2.3.1.2 and 2.3.1.3. The WBN FSAR discusses the piping classification inSection 3.2.2, which states:Fluid system components for the Watts Bar Nuclear Plant that perform a primary safetyfunction are identified by TVA Classes A, B, or C (see Section 3.2.2.7 for HVAC SafetyClassifications). These piping classes are assigned to fluid systems based on the ANSSafety Classes 1, 2a, and 2b, respectively, which are assigned to nuclear power plantequipment per the August 1970 Draft of ANSI N18.2, "Nuclear Safety Criteria for theDesign of Stationary Pressurized Water Reactor Plants." Fluid system components,whose postulated failure would result in potential offsite doses that exceed 0.5 Rem tothe whole body, or its equivalent to any part of the body, are identified as TVA Class Dand are based on ANSI N 18.2 (Aug., 1970 draft) Safety Class 3 and RegulatoryGuide 1.26. The TVA piping classification system for WBNP does not conform strictly tothe guidance of Regulatory Guide 1.26 (which was not in effect on the docket date forEl-17 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"the Construction Permit). The ANS safety classification of each component has beenconsidered in the various aspects of design, fabrication, construction, and operation.Thus, there is no ASME requirement to perform testing on this piping, since it is not scopedinto the required safety functions listed in IWD-1210.The HPFP Class 3 piping and components are a part of the augmented ASME program thatWBN has established to test the active components (e.g., valves and pumps) in a mannersimilar to the ASME devices. The passive components, such as piping, are not testedspecifically by the augmented program but by the individual programs which the passivecomponents support. For the two buried headers, there are no valves or pumps.The following is the testing the Train A and B buried headers do experience:" The HPFP system, including these buried headers, is brought to system pressure atleast once per week for periodic pump runs per the FPR, Part II, Section 14.2. This isnot a formal test of the piping but it does serve to allow plant personnel to observe thepiping at system pressure. Note that the ASME system pressure test requirement is tobring the piping to system pressure once per period (one-third of an Inservice Intervalof 10 years; nominally every 3.3 years)." The valves that isolate the buried trained headers are cycled once per year." The headers are flow tested at least once every 3 years as a part of the fire protectionflow test of the hydrants, sprinklers, and hose stations, as discussed in Questions 5 and10 above.12. NRC Question (RAI FPR VI1-18)It is unclear whether there is fire detection in the tunnel of Fire Zone 692.0-A B. A plainreading of Part VII, Section 8.3.3.4 of the FPR would indicate that, although there is nosuppression, there is detection. However, both Table I-I, and Part VII, Section 3.1.1,indicate that there is no detection or suppression.Clarify whether there is detection in the tunnel of Fire Zone 692.0-A I B.TVA Response:It is noted the question refers to Section 8.3.3.4, but it should have referred toSection 8.3.3.2. The fire detection system provided for 692.0-Al B does not extend into thetunnel. Section 8.3.3.2 will be revised to clarify that the tunnel from 692.0-Al B is notprovided with detection or automatic suppression. However, as documented in Section8.3.3.2, the reader is directed to Part VII, Section 3.1.1 where the lack of detection andsuppression in the tunnel has been previously justified and documented. This change willbe submitted in the next revision to the FPR.El-18 ENCLOSUREIResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"13. NRC Question (RAI FPR VI1-19)A number of areas where a fire causes a manual action to be performed lack both detectionand suppression. Examples of these areas are found in Part VII, Sections 8.3.14, 8.3.15,8.3.18, 8.3.19, and 8.3.24 of the FPR.Provide a description of the entry conditions for the manual action, since detection of the firethrough automatic means is not available.For example, how will the operators know to perform Operator Manual Action (OMA) 1016(for a fire in room 729.0-A2, for example), without knowing a fire has occurred in the area?This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:The feasibility and reliability evaluations for Part VII, Sections 8.3.14 (Room 729.0-Al -Unit 1 South Main Steam Valve Room), 8.3.15 (729.0-A2 -Unit 1 North Main Steam ValveRoom), 8.3.18 (729.0-Al0 -Unit 2 North Main Steam Valve Room), 8.3.19 (729.0-Al1 -Unit 2 South Main Steam Valve Room), and 8.3.24 (729.5-A17 -Unit 2 Shield Building VentRadiation Monitoring Room) have been deleted. An engineering evaluation for each ofthose rooms has been completed and will be documented in Part VII, Section 3.1 of theFPR. None of these rooms contain a significant quantity of in situ combustibles or anycredible ignition source that would result in a fire that would require a shutdown on either ofthe units (see following evaluation of 729.0-Al as example). These revisions will beincluded in the next FPR submittal.Fire Area 12 contains two rooms (729.0-Al-Unit 1 South Main Steam Valve Room and737.0-A6-Air Lock into 729.0-Al). Neither of these rooms is provided with detection orautomatic suppression. Room 737.0-A6 only contains lighting and it is not required forfire safe shutdown nor would its failure require a unit shutdown. Room 729.0-Alcontains valves in the Feedwater and Main Steam systems (systems 1 and 3) that arerequired for normal operation and post fire safe shutdown. The other components (e.g.area radiation monitors, lighting, exhaust ventilation, etc.) are not required for fire safeshutdown nor would their failure require or cause a unit shutdown.The two rooms are of reinforced concrete construction which is 12 to 36-inches thick andhave fire resistance ratings of 2-hours for those barriers that separate the rooms fromadjacent rooms in the Auxiliary Building and 3-hours from the Unit 1 Reactor Building.The walls that separate room 729.0-Al from the Yard are minimum 24-inches thick, butare not assigned a fire resistance rating. Room 737.0-A6 has a floor area of 77-ft2 and aceiling height of 8-feet. Room 729.0-Al has a floor area of 874-ft2 and a ceiling height of57-feet. An effective detection system is not viable due to the ceiling height and the highambient temperature and humidity in this room.The in situ combustible loading of 729.0-Al consists of small quantities of lubricating oilin various valves and miscellaneous plastics associated with area radiation monitors,lighting, and small electrical control panels and boxes. The total combustible loadingEl-19 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"results in a fire severity of less than 1-minute (insignificant). The in situ combustibleloading in 737.0-A6 is due to the light covers and results in a fire severity of less than1-minute (insignificant). There are no ignition sources in 737.0-A6. The only credibleignition sources in 729.0-Al are the radiation monitors and valve motors (power circuitsare de-energized when the valve is in its normal alignment). Neither of these areconsidered to be a significant ignition source (their failure would not damage any othercomponent). Transient combustibles are controlled in accordance with combustiblecontrol zones identified on the Compartmentation drawings.Failure of Feedwater and Main Steam valves would be detected by systeminstrumentation that would activate alarms in the Main Control Room to alert theoperating staff of a problem and the staff would address the problem using normal plantoperating procedures. There are no credible fires in Fire Area 12 that would require orcause emergency shutdown of either unit. Therefore, the lack of detection andautomatic suppression does not significantly decrease the fire protection or safety of theplant and WBN requests approval for not providing detection and automatic suppressionin Fire Area 12.An extent of condition review has been performed and the results will be included in the nextrevision of the FPR.14. NRC Question (RAI FPR VII-20)There are inconsistencies in the level of detail provided in Part VII of the FPR regardingOMA Staffing Requirements. Two examples:1. Section 8.3.42.5 includes a relevant paragraph regarding OMAs 1022 and 1023, asUnit 2 OMAs. This paragraph is relevant since it provides actual demonstration time forthe combination of actions for Unit 1 (mirror image actions) and describes that the OMAsoccur are performed in the same room. This paragraph is followed by 12 paragraphsthat are not related to the submitted evaluation.2. Section 8.3.9.8 is only one paragraph with one sentence listing the operator and theactions that they are performing. Of the eight operators, only the seventh operator isperforming the OMAs described in the evaluation. This paragraph lacks the usefuldescription of the demonstration time for the combination of actions and a statementregarding the rooms that the OMAs need to be performed. This is especially relevantsince OMAs 1016 and 1024 are described as performed in Room 737.0-A9 and OMA1482 is described as performed in Room 713.0-A I B.Provide consistent level of detail for the Staffing Requirements sections of Part VII, Section8 Evaluations. Include information regarding combination of actions that are performed bythe operator or operators that are performing the OMAs evaluated.This RAI may involve an update to the FPR to incorporate the response to the RAI.El-20 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"TVA Response:The OMA Staffing Requirements of the feasibility and reliability evaluations in Part VII,Section 8 will be revised to provide a consistent level of detail for each evaluation byeliminating the details of the Unit 1 OMAs. Staffing discussions will focus on the AssistantUnit Operators (AUOs) performing the evaluated Unit 2 and common OMAs and providespecific discussion of actions performed by those AUOs prior to or concurrent with theevaluated OMAs. Unrelated actions will be summarized to indicate that an adequatenumber of AUOs are available for all operator actions. These changes will be provided inthe next FPR submittal. The revised version of sections 8.3.9.6 (8.3.9.8 from the August 15,2011 submittal is now 8.3.9.6, as OMAs 1016 and 1024 are no longer required for713.0-AlA) and 8.3.42.5 shown below are examples of the level of detail which will beprovided for each of the staffing requirement sections in the next revision of the FPR.8.3.9.6 Staffing Requirements for a Fire in Room 713.0-AlAA fire in 713.0-AlA requires 18 Unit 1 actions requiring five AUOs and three Unit 2actions (OMAs 1022, 1023, and 1482) requiring two AUOs for a total requirement of7 AUOs. Therefore, the staffing of eight.AUOs for the station is sufficient toaccomplish all of the required Unit 1 and Unit 2 manual actions, if there is a fire inroom 713.0-AlA.a. One AUO will perform OMA 1482 to throttle seal injection flow in room 713.0-A1Bwithin 60 minutes.b. A second AUO will perform OMAs 1022 and 1023 to modulate steam generator#3 and #4 PORVs at the local N2 station in room 729.0-Al5 within 60 minutes.These concurrent actions performed at the same location require no additionaltransit time.8.3.42.5 Staffing Requirements for a Fire in Room 757.0-A9A fire in 757.0-A9 requires three Unit 2 actions (OMA 1446, 1023, and 1022)performed by two AUOs and 46 Unit 1 actions performed by five AUOs for a totalof seven AUOs. Therefore, the staffing of eight AUOs for the station is sufficient toaccomplish all of the required Unit 1 and Unit 2 manual actions, if there is a fire inroom 757.0-A9.OMAs that are related to a fire in 757.0-A9 are as follows:a. One AUO is required to operate 2-ISIV-1-403E2 (OMA 1023) and 2-ISIV-1-402E2 (OMA 1022) to control secondary pressure from the local N2 station inroom 729.0-Al 5 within 60 minutes. These concurrent actions are performed atthe same location with no additional transit time.A second AUO.performs two important to safe shutdown OMAs. Unit 1OMA 1411 in room 692-AlA within 20 minutes and Unit 2 OMA 1446 in room772-A15 within 70 minutes.El-21 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"15. NRC Question (RAI FPR V11-21)There exists a conflict between Part VII, Sections 4.5 and 8.3.44.2, of the FPR.Part VII, Section 8.3.44, includes OMAs required for safe shutdown. Part VII, Section8.3.44.2, references Part VII, Section 4.5, for justification of why no detection is required inthe Refueling Room, 757.0-A 13. Part VII, Section 4.5 states as part of the justification for nodetection: "A fire in the Refueling Room or in the adjacent rooms of Fire Area 10 will notimpact FSSD capability." The quoted statement in Section 4.5 conflicts with the need forOMAs in 757. O-A 13, Refueling Room.Resolve this inconsistency between the sections of Part VII. Provide a technical justificationfor the lack of detection in the Refueling Room in the context of the need for OMAs in thatarea.This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:This question is linked to Question 22, Sub-question [1] (RAI FPR VIII-22). The belowresponse addresses both RAI FPR VII-21 and VIII-22, Sub-question [1].The Engineering Evaluation documented in Part VII, Section 4.5 will be revised to provideadditional justification for the lack of detection in the Refueling Room and New Fuel StorageVault and this will also eliminate the need for the OMAs. Therefore Part VII, Section 8.3.44is being deleted. These changes will be included in the next FPR submittal. The newPart VII, Section 4.5 is as follows:4.5 LACK OF AUTOMATIC DETECTION IN 757.0-A13 (REFUELING ROOM) AND NEWFUEL STORAGE VAULT (741.5)REQUIREMENT -Sections F. 12 and F. 13 of Appendix A to BTP 9.5-1 identifies thatautomatic fire detectors should be installed in the areas of new fuel and spent fuel pools.DEVIATION -The refueling area (Refueling Room 757.0-A13 which includes the NewFuel Storage Vault, Spent Fuel Pool and Fuel Transfer Canal) is not provided with anautomatic detection system.JUSTIFICATION -The Refueling Room is part of Fire Area 10, but it is not provided withinstalled automatic detection. Standpipe and hose stations are provided in the room andin adjacent rooms. It is a large open area (floor area of 16,164-ft2) with nominal ceilingheight of 56-ft.The only ignition sources that could impact a FSSD component or cable are the Train Aand B Auxiliary Air Compressors. These compressors are required to provide backup air(to the Train A and B air header) if the normal air supply from the Station AirCompressors is unable to maintain minimum pressure on the air header. A fire involvingE1-22 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"either of the Auxiliary Air Compressors (neither is in the zone of influence of the other)would not impact the normal air supply or the other Auxiliary Air Compressor.A fire on Train A compressor could cause 0-FCV-32-82-A to close which would block airflow from the Station Air header to the Train A air header. The normal Station Air headerwould still be backed up by Train B air header supplied from the Train B compressor. Afire on Train B compressor could cause 0-FCV-32-085-B to close which would block airflow from the Station Air header to the Train B header. The normal Station Air headerwould still be backed up by the Train A air header supplied from the Train A compressor.Worse case fire induced failure would be loss on one train of auxiliary control air whichcan be handled by plant procedures without shutting down either unit.Other FSSD circuits routed in conduits through the Refueling Floor area are outside thezone of influence of the compressors. Therefore, a fire in the Refueling Room or inadjacent rooms of Fire Area 10 will not impact on FSSD capability. Part VI contains thefire hazard analysis (FHA) discussion of the FSSD analysis for Fire Areal0.During normal operations, the in situ combustible loading for the Refueling Room andNew Fuel Storage Vault is insignificant and results in an equivalent fire severity of lessthan five minutes. The combustible materials in the Refueling Room are widelydispersed which further diminishes the magnitude of a postulated fire. During an outage,the area is manned and any postulated fire from transient material due to refuelingactivities would be quickly detected and extinguished. The New Fuel Storage Vault isonly accessible from the Refueling Room and that access is normally closed with a steelhatch cover. The cover is removed when new fuel is received and stored until neededfor a refueling outage. There are no ignition sources in the New Fuel Storage Vault.Based on the insignificant in situ combustible loading during operations, high ceiling,large volume, good compartmentation, and lack of impact on FSSD, TVA requestsapproval for not providing automatic detection and suppression for the WBN RefuelingRoom.16. NRC Question (RAI FPR V11-22)A number of the evaluations in Part VII, Section 8 of the FPR state that a particular roomdoes not have dedicated procedures for fire safe shutdown. One example is Section8.3.45, which states in part: "Room 757.0-A 14 does not currently have a dedicatedprocedure for fire safe shutdown."The submitted FPR is intended to be the as-designed version of the FPR. Therefore, thestatements should either include a reference to a commitment or be written as if theprocedures have been completed, even if all the procedures are not yet completed. Thesestatements indicate that it would be acceptable not to have a procedure.Confirm that there will be procedures for these OMAs.This RAI may involve an update to the FPR to incorporate the response to the RAI.El-23 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"TVA Response:TVA confirms there will be procedures for each affected room that address each OMA. TheOMAs identified in the FPR are to be verified by walkdowns and documented in AOl 30.2prior to fuel load. The statement that a room does not have dedicated procedures for FSSDwill be deleted for the evaluations. These revised evaluations will be included in the nextFPR submittal.17. NRC Question (RAI FPR VII-23)Part VII, Sections 8.3.86, 8.3.87, 8.3.88, and 8.3.89 [Accumulator Room 2, Fan Room 2,Unit 2 Lower Containment Instrument Room, and Outside Crane Wall (North), respectively],lack descriptions of fire detection, fire suppression, combustibles and ignition sources.Provide the missing information. If detection is not available in the rooms, provide atechnical justification that operators will have sufficient information available to know toinitiate the OMAs.This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:Engineering Evaluations will be performed for the four fire zones (2RA2 -AccumulatorRoom 2, 2RF2 -Fan Room 2, 2RIR -Instrument Room. and 2RO-N -Outside Crane Wall[North]) identified in NRC's request and will be added to Part VII, Section 3.1 of the FPR.These evaluations will be included in the next FPR submittal. The in situ combustibleloading in each of these fire zones is insignificant, except for 2RO-N (fire load severity islow) and there are no credible ignition sources in the rooms. The major contributor to thecombustible load (92%) in this zone is due to the expansion joint material. Transientcombustibles are controlled in accordance with combustible control zones identified on theCompartmentation drawings. Therefore, there is no threat to FSSD components located inthe room. The addition of detection and suppression in these rooms would not significantlyincrease fire protection of safe shutdown capability in the rooms.WVA has performed a generic review for Unit 2 and identified all rooms in the Unit 2 ReactorBuilding without detection, but contains FSSD components. Additional information will beadded to the next revision to the FPR to address these rooms.18. NRC Question (RAI FPR V11-24)Part VII, Section 8.3.10.5, of the FPR, discusses OMA 1275 in Fire Zone 713.0-A IB. In thissection, travel time has been approximated for each of the operator manual actions.Provide the technical basis for assuring that the travel time includes all likely locations of theAuxiliary Unit Operators where they could be at the beginning of the actions.This RAI may involve an update to the FPR to incorporate the response to the RAI.El-24 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"TVA Response:Recognizing that the AUOs could be working anywhere in the plant at the onset of a fire,one of the initial general fire response actions (prior to reactor trip) by the control roomoperator is to summon the AUOs to the control room (auxiliary control room for a ControlBuilding fire) for a confirmed fire located in the Control Building, Auxiliary Building, eitherReactor Building, or annulus. At t=O, AUOs assigned to Appendix R OMAs would be in theMain Control or Auxiliary Control Room where they would receive their specific assignmentsand procedures (see FPR Part V, Section 2.2, Safe Shutdown Procedures). OMArequirements vary depending upon fire location, and AUO tasks are not pre-assigned toindividual AUOs. Since the AUOs come to the control room to receive their assignments, alltravel times start from the control room.Additionally, TVA is eliminating the use of approximate times and the symbol for"approximate." This change will be submitted in the next FPR.19. NRC Question (RAI FPR V11-25)Part VII, Section 3. 1.1, of the FPR was changed to indicate more rooms within Fire Area 1contain FSSD equipment. In particular, the following rooms were changed from "None"to "Yes" in the summary table: 674.0-A1, 674. 0-A2, 692.0-A29, and 692. 0-A30.Room 692. O-A 18 was changed from "Yes" to "None."The reviewers have identified the following inconsistencies:0 [1] Room 674. O-A2 is indicated as containing FSSD equipment, but there is noevaluation provided for this room. Additionally, Table I-I shows this room as having noFSSD equipment.* [2] The new evaluation provided for rooms 692. 0-A29 and -A30 (one sentence) isinsufficient. Provide a level of detail equivalent to the other evaluations.* [3] Part VII, section 3. 1.1, was changed to add an evaluation of room 692.0-A23.However an evaluation for this room already exists in section 3.1.7.* [4] The evaluations in Section 3.1.1 for rooms 692. O-A 10, -A22, and -A23 are notindicated in Table I- I (or Part VI for -A 10).This RAI may involve an update to the FPR to incorporate the response to the RAI.E1-25 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"TVA Response:[1] Room 674.0-A2 does not contain FSSD components. Table 3.1.1 will be corrected toshow "None" for this room.[2] The evaluation in the FPR for rooms 692.0-A29 and -A30 will be revised as follows:Transient combustibles are controlled in accordance with combustible control zonesidentified on the Compartmentation drawings. This would include posting a firewatch during the work process. The in situ combustible loading for each of theserooms is Insignificant and there are no significant ignition sources. The FSSDrequired cables are routed in conduits and the minimal fire hazards in the roomswould not be expected to endanger functionality of these cables."[3] Part VII, Section 3.1.7, Fire Area 68, will be deleted and the appropriate places in TableI-1 and Section VI of the FPR will be corrected.[4] Table I-1 has been corrected to refer to Part VII, Section 3.1 for rooms 692.0-Al 0, -A22 and -A23. As part of the extent of condition review, Part VI of the FPR has beenrevised to refer to Part VII, Section 3.1, for room 692.0-Al0. Part VI of the FPRalready referred to this reference for the other two rooms.During the August 31, 2011 public meeting, it was discussed that room 692-Al 8 has noFSSD equipment, but the evaluation was originally retained. This evaluation will beremoved in the next revision to the FPR.The changes addressed in this item will be submitted in the next FPR.20. NRC Question (RAI FPR Vi11-21. 1)RAI FPR VIII-21 requested that TVA:Identify the locations where combustible oil filled transformers are installed.Provide the locations to the level of detail of room subdivisions used to assembleanalysis volumes (for example, room 692. O-A 1 has been subdivided into 692. 0--AIA1, -AIA2, -AIA3, -AlAN, -AIB1, -A1B2, -A1B3, -AlBN and-A1C).The explicit intent of this question was to determine which portion of the subdivided areashouses the transformers with combustible liquid.For example, Analysis Volume A V-005 in Fire Area I includes room 692. O-A 1, which issubdivided into numerous areas including A I BN. A1BN is central to the entire area, andwould be considered a "buffer zone." If transformers are located in this portion of A V-005,they have the potential to impact the volume analysis of Part Ill, Section 10.3. 1. Specifically,Section 10.3.1 relies on Deviation Request 2.4 of Part VII of the FPR for the treatment ofintervening combustibles. Combustible liquid filled transformers were not listed in DeviationRequest 2.4, whereas much less significant combustibles were, such as plastics injunctionEl-26 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regardina "Fire Protection Report"boxes. Therefore, even with enhanced suppression provided in the area, specific analysisof combustible liquid transformers should be included where they could represent anintervening combustible in such a "buffer zone."[V] Provide the specific sub-area where each of the combustible liquid transformers arelocated. Area and analysis volume do not provide sufficient information regarding where inthe plant these transformers are located. In particular, it appears that this detail was notprovided (in the August 5, 2011, TVA letter) for transformers O-OXF-228-3, -228-4, -226-A,and -226-B.[2] If any of the combustible liquid transformers are located in "buffer zones," as described inPart Ill, Section 10.3.1, provide the technical justification that locating such an ignitionsource with integral combustibles in that buffer zone would not impact safe shutdowncapability.[3] In addition, update Section 2.4 of Part VII to include combustible liquid filled transformersas an intervening combustible, if these transformers are in areas that have been evaluatedfor intervening combustibles.TVA Response:[1] The transformers O-OXF-228-3 and 0-OXF-228-4 are located in the Auxiliary Building,el. 692. They are located at the far sides of the el. 692 general area as shown inFigures 1 and 2 (Attachment 3). Transformer 0-OXF-228-3 is in the sub-area 692.0-AlAl and 0-OXF-228-4 is in the sub-area 692.0-AlBi as shown on Figure 3(Attachment 3).The Transformers 0-OXF-226-A and 0-OXF-226-B are located in the Intake PumpingStation (IPS), Electrical Board Room, el. 711 as shown on Figure 4 (Attachment 3).Transformer 0-OXF-226-A is located in the sub-area IPS-CC-A and 0-OXF-226-B islocated in the sub-area IPS-CC-B. Figure 5 (Attachment 3) provides a general electricalcomponent layout sketch of these transformers.[2] As shown in Figures 1 thru 3, the transformers at Auxiliary Building, el. 692 are not inthe "buffer zones" for the analysis and are adequately separated by the buffer zone.The Electrical Equipment Room in the IPS is located on elevation 711.0 and is ofreinforced concrete construction with a minimum thickness of 12 inches. The room hasa floor area of 2,608 ft2 and a nominal ceiling height of 16 ft. The south wall (separatesthe Electrical Equipment Room from adjacent IPS rooms) is a 3-hour fire rated barrier.The other three walls are below grade, and the ceiling separates the room from theoutside. The in situ combustible load in the room results in a fire severity classification ofModerate (<160,000 Btu/ft2); however, the majority of the combustible load is due toinsulation on the cables in trays (83%) and insulating oil in the two transformers (13%).Each transformer is inside a curbed area with a capacity of approximately 370 gallons.The Dow Corning 561 silicone transformer liquid (see Attachment 4 for data from DowCorning) would either self-extinguish itself or be extinguished by the suppression systemprovided for the room.E1-27 ENCLOSURE 1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"The Electric Equipment Room is provided with detection and automatic suppression.The detection system would detect a postulated fire in its early development and alarmsin the MCR would alert staff to the fire. If the fire increased in intensity, the automaticsprinkler system (sprinkler heads are 212OF rated) would operate and extinguish orcontrol the fire until the Fire Brigade responds.The FSSD requirements for a fire in the IPS are for a minimum of two ERCW pumps tobe unaffected by, the fire. The electrical power and control cables for the ERCW pumpsenter the Electrical Equipment room from the Train A and B conduit duct banks on thewest (Train A) side and east (Train B) sides of the room. The cables exit the trays alongthe south wall and are embedded in the concrete until they exit near each pump. Theworst case location of a fire (i.e., one of the transformers) would only impact cables fortwo of the ERCW pumps. This leaves six of the pumps (minimum FSSD requirement istwo pumps) available. Even applying the very conservative requirements of Appendix R,Section III.G.2, the minimum required number of Train A and Train B pumps complieswith the acceptable separation requirements of Section IIl.G.2.b (20 feet withsuppression and detection with no continuous intervening combustibles).[3] Part VII, Section 2.4 will be revised to include the oil filled transformers and will beincluded in the next FPR submittal.21. NRC Question (RAI FPR VIII-21.2)The response to RAI FPR VIII-21 in the August 5, 20.11, TVA letter contains the followingstatement as a basis of acceptability: "Silicone fluid fires are extinguished in 20 to 30seconds with a water application of 0. 15 gpm/sq. ft."Provide a basis for this statement using technical analysis or test results from anindependent testing laboratory, or provide other technical information that supports thestatement.TVA Response:This information relative to silicone dielectric fluids being extinguished in 20 to 30 secondswith a water application of 0.15 gpm/sq. ft. was provided in the vendor information on thisfluid. Please refer to Section 2.5.2, page 2-11 of the attached vendor information(Attachment 4) for the source information on this water extinguishment requirement.22. NRC Question (RAI FPR VII-22)A change was made in Part VIII, element F. 12, of the FPR, to delete text in the "PlantConformance" column that indicated that automatic detection is installed in the fuel receiptarea and New Fuel Vault. Additionally, the following was added to the "Alternatives"column: "Detection is not provided in the New Fuel Storage Vault (el. 741.5). Refer to PartVII, Section 4.5 of the FPR."E1-28 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"Part VII, Section 4.5 is an evaluation of the lack of detection in the refueling room (757.0-A 13), and does not mention the New Fuel Storage Vault or any other rooms.[1] Provide a technical justification for the lack of automatic detection in the New FuelStorage Vault. One means might be to expand the evaluation in Part VII, Section 4.5, toencompass this area.[2] Is there automatic detection installed in the fuel receipt area? If not, provide a technicaljustification for the lack of automatic detection in this area.This RAI may involve an update to the FPR to incorporate the response to the RAI.TVA Response:[1] See Question 15 (RAI FPR VII-21).[2] In accordance with the WBN Fuel Handling Instruction (FHI), fuel receipt process beginswith the arrival of the truck at the WBN site but new fuel receipt is only performed in theRefueling Floor, Rm. 757.0-Al 3, since in this area is the only room where the new fueltransportation casks are opened. The new fuel transportation casks are designed toprotect the fuel from normal over-the-road accidents such as impact and fire. Thus,when the new fuel transportation casks are in their closed shipping configuration, fire isnot a concern. The Refueling Floor has been the location where the fuel transportationcasks are opened since the first fuel was received at WBN. The justification for noautomatic detection for the fuel receipt area was provided as the justification for noautomatic detection on the Refueling Floor. The justification for the no automaticdetection for the Refueling Floor is provided in the FPR, Part VII, Section 4.5 (see [1]above).23. NRC Question (RAI FPR 11-26.1) (Received in email dated September 20, 2011 fromNRC [Justin Poole, NRRD)In the response to RAI FPR 11-26 (ML 11 129A 158), TVA noted that the frequency of the GL82-21 annual fire protection audit has been changed to 24 months and refers to an August28, 2002 letter (ML022460173) to the NRC documenting this change. TVA states in theAugust 28, 2002 letter that this change was implemented using a performance-basedschedule as allowed by the NRC Regulatory Guide 1.189 (section 1.7.10.1 of revision 0).Provide more detail regarding this change. In particular,[1] A summary of the performance based process used to make the change[2] A summary of how the change is being monitored.This summary information would be appropriate to include in the FPR at the correct level ofdetail.E1-29 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"TVA Response:[1] A summary of the performance-based process used to make the change:The change was made using 10 CFR 50.54(a)(3)(i) which allows revision to thoseQuality Assurance (QA) programs that use a QA standard approved by the NRC whichis more recent than the QA standard in the licensee's QA program at the time of theupdate.Attachment 5, Fire Protection Program Audit Frequency, list the audits and assessmentsthat have been performed over the past several years to implement this change. Thisprocess is described in the Nuclear Quality Assurance Plan (NQAP) (TVA-NQA-PLN89-A), along with the associated supporting Audit and Assessment Procedures.This change committed TVA through TVA-NQA-PLN89-A to Regulatory Guide 1.189,Revision 0, dated April 2001. Attachment 5, Fire Protection Program Audit Frequency,shows that TVA has been completing off-year performance based assessments inaccordance with Regulatory Guide 1.189, Revision 0, dated April 2001, with oneexception. The exception occurred between the 2003 and 2005 Audits. During thepreparation for the Audit in 2005, the omission was identified. This omission wasentered into the corrective action program. Corrective actions included further updatingof the NQAP and associated supporting Audit and Assessment Procedures. Theseactions have been effective in that no recurrences have occurred since that time.Additionally, it can be seen that if QA is not satisfied with a station's performance, thatstation has been subject to additional auditing (i.e., 2002 at Sequoyah).Attachment 5 provides detailed review of the Fire Protection Program Audit Frequencyand demonstrates that TVA has been satisfactorily meeting the requirements ofRegulatory Guide 1.189, Revision 0, dated April 2001.[2] A summary of how the change is being monitored:As noted previously, one exception occurred early in the transition to RegulatoryGuide 1.189, Revision 0. Corrective actions from that occurrence, along with resultsfrom the associated supporting Audit and Assessment Procedures, ensure thecommitment was further refined in TVA-NQA-PLN89-A during Revision 14-A2.The periodic scheduling and performance of audits and assessments monitors thehealth of the fire protection program, and if QA identifies degradation in the program at aparticular site, the audit frequency for that site would be increased. It can be seen in thetable that in one case, since this change was implemented, QA was not satisfied with astation's performance and that station has been subject to additional auditing (i.e., 2002at Sequoyah).With regard to "This summary information would be appropriate to include in the FPR at thecorrect level of detail," the following revision to Part II, Section 7.7 will be included in the nextFPR:E1-30 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"The Fire Protection Program uses the applicable parts of the TVA Nuclear QualityAssurance Plan (TVA-NQA-PLN89-A) to manage the audit frequencies. This QAprogram is further described in corporate standards and implementing procedures. Anychanges to the NQAP are controlled under 1OCFR50.54(a).24. NRC Question (Received during August 31, 2011 meetinq in Rockville, Md.)Part VII, Section 8 -The Section uses the term "Fire Room." This term is not used in otherparts of the report. Change the term to simply "Room." This appears in Section 8.3.1, etc.Perform a generic review and correct any changes in to the next FPR submittal.TVA Response:A review of Part VII, Section 8 has been performed and the section has been revised toreplace "fire room" with "room." The change will be included in the next revision to the FPR.25. NRC Question (Received during August 31, 2011 meeting in Rockville, Md.)Part VII, Section 8.3.52.2 uses the term "automatic action sprinklers." The proper term is"preaction" sprinklers. Perform a generic review and correct any changes in to the next FPRsubmittal.TVA Response:The term preaction sprinklers is a subset of automatic sprinklers. The term automaticsprinklers is used throughout the FPR. A review has been performed to change automaticaction sprinklers to automatic sprinklers. The change will be included in the next revision tothe FPR.26. NRC Question (Received during August 31. 2011 meeting in Rockville, Md.)Part II, B. 14. 1.C -Add discussion that each unit's refueling outage is 18 months; therefore,the use of the term "Refueling Outage" gets everything tested in one unit's outage or theother so that everything has a test within it's 18 month frequency.TVA Response:TVA agrees the terminology of "Refueling Outage" could result in confusion with two unitoperation. To address this issue, the following changes will be included in the next FPRsubmittal:Part II, Section B.14.1.c:TIR 14.1.c is the performance of a functional test on each of the required smokedetection and restorable heat detection instruments which are in any inaccessible area.El-31 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"This test is performed for the unit in a refueling outage. The expected frequency for thistesting is each unit's Refueling Outage and is based on operating experience.Part II, B.14.3.c:TIR 14.3.c ensures that each automatic spray/sprinkler system valve actuates to itscorrect position. These deluge valves for preaction systems have limited means toensure a cycle of travel is achieved. Industry practice on cycling these valves byclosing the isolation valve all but a few turns until the deluge valve opens and thencompleting the closing of the isolation valve will be used. This TIR also ensures thateach testable valve in any inaccessible area will travel through at least one cycle. Anypushbuttons provided at deluge valves for manual start of the fire pumps are not testedas a part of this TIR. These pushbuttons are provided for when the deluge valve ismanually activated. Upon discovery of a fire, plant personnel are trained to report allfires before trying to fight them. Additional administrative controls are in place to ensurethat a fire pump(s) is running when a fire is reported. A unit's Refueling Outagefrequency was developed considering that many surveillances can only be performedduring an outage. Standard Technical Specification requirements and operatingexperience have shown these components routinely pass the TIR when performed onthe 18 months/Refueling Outage frequency. Therefore, the frequency was concluded tobe acceptable from a reliability standpoint.Part I11 B.14.3.d:TIR 14.3.d performs a general, floor level visual inspection of each spray or sprinklersystem once every 18 months for accessible areas and for the unit in a RefuelingOutage for inaccessible areas. This general inspection identifies any abnormalconditions and/or physical damage to the riser, sprinkler piping network, and hangers.This inspection includes assurance that spray/sprinkler head discharge patterns are notobstructed from providing protection from the hazards present. This inspection is notintended to perform a field verification of the design of the installed spray/sprinklersystem. The 18 months/Refueling Outage frequencies have been established and areconsistent with standard Technical Specification requirements. Design and modificationcontrols exist to prevent improper fire protection system installation or permanentimpairment of operation through improper installation of plant equipment.Part 11, B.14.3.e:TIR 14.3.e verifies during outages that each testable valve in any inaccessible area isvisually inspected to be in its correct position. The test is performed during each coldshutdown exceeding 24 hours unless the TIR was performed in the previous 92 days.The verification is to be performed each 92 days during extended outages. Thefrequency for the TIR is based on the assumption that the required valves cannot betested until the plant is in cold shutdown for more than 24 hours. Valves that arelocked, sealed, or otherwise secured in position need only be verified to be locked,E1-32 ENCLOSURE IResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"sealed, etc., since these were verified to be in the correct position before locking,sealing, or securing. A frequency of 92 days during outages has been established andis more conservative than the inspection criteria established for primary system valvesthat are locked, sealed, etc. The expected frequency for this testing is each unit'sRefueling Outage and is based on operating experience.Part II, B.14.6.e:TIR 14.6.e ensures that each dry standpipe water flow device actuates to its correctposition upon an initiation signal. The dry standpipe control valve is a deluge valve forwhich there is limited means to ensure a complete cycle of travel is achieved. Forcycling these valves, the industry practice of closing the isolation valve all but a fewturns until the deluge valve opens and then completing the closing of the isolation valve.Also, each testable valve in any inaccessible area will travel through at least one cycle.The pushbuttons associated with these hose stations in the Reactor Buildings not onlyprovide a means to open the deluge valve that allows water into the normally drystandpipe system as discussed in Section 12.2 but also start the fire pumps. Althoughthese Reactor Building hose stations are manual and plant personnel are trained toreport a fire before fighting it, there are no administrative controls to ensure the delugevalve is activated as there are for the start of the electric motor driven fire pump(s).Therefore, these push buttons are tested. Any other pushbuttons provided at hosestations other than the Reactor Buildings for manual start of the fire pumps are nottested as part of this TIR. The 18 month frequency for accessible areas and each unit'sRefueling Outage frequency for inaccessible areas was developed considering thescope and requirements of some tests and inspections can only be performed during aunit outage. Operating experience has shown these components routinely pass the TIRwhen performed on the 18 month/Refueling Outage frequency. Therefore, thefrequency was concluded to be acceptable from a reliability standpoint, and isconsistent with standard Technical Specification requirements.Part II. B.14.6.f:TIR 14.6.f requires performance of a visual inspection of the fire hose stations that arein any inaccessible area to assure all required equipment is at the station and thestation is not blocked or obstructed. The Refueling Outage frequency was developedconsidering that many tests and inspections can only be performed during a unitoutage. Operating experience has shown these components routinely pass the TIRwhen performed on each unit's Refueling Outage frequency. Therefore, the frequencywas concluded to be acceptable from a reliability standpoint, and is consistent withstandard Technical Specification requirements.Part II, B.14.8.d:TIR 14.8.d requires each unit's Refueling Outage frequency visual inspection ofapproximately 33-1/3 percent of the surface area of fire rated assemblies/fire barriers toE1-33 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"determine Operability. Inspection of bellows, metal plates, ERFBSs, radiant energyshields, or insulation covering a penetration seal, provides verification of the fire ratedassembly/fire barrier integrity, provided there is no apparent change in appearance orabnormal degradation. Inspections validate their functional integrity and ensure thatfires will be confined or adequately retarded from spreading to adjacent portions of thefacility.Part II, B.14.9.c:TIR 14.9.c requires that the EBL in inaccessible areas inside the Unit 1 and 2 Annulusbe replaced each refueling outage for that unit and that the tests and inspectiondescribed under bases 14.9.a be performed to ensure EBL operability. This is beingdone due to the ALARA considerations in the Reactor Building and the limitedaccessibility during plant operation. The surveillance frequency and battery replacementare considered conservative and reasonable based on the fact that these are 15 yearservice life batteries that are being replaced on a refueling outage frequency.27. NRC Question (Received durinq August 31, 2011 meeting in Rockville, Md.)Part II, B. 14.3.1. a -The sentence reads wrong. There are too may "detection inoperable"words.TVA Response:This section was in the as-designed FPR sent to NRC on August 15, 2011, and incorrectlyadded one "detection" too many. The FPR, Part II, Section B.14.3.1.a will be revised asfollows and will be submitted in the next FPR:When detection or both suppression and the associated detection are inoperable in anarea, then the more stringent compensatory actions are needed. If only the water basedsuppression is inoperable, then the early warning detection system will provide moreextensive coverage of the area and faster notification than can be provided by a firewatch. Therefore, it is appropriate to provide a lesser degree of fire watch coverage(i.e., Hourly roving fire watch). When the detection is inoperable and the associatedsuppression is still operable then the more restrictive compensatory action is required. Inthis situation, not only is the early warning capability lost, but so is the automaticactuation capability of the suppression system.28. NRC Question (Received during August 31, 2011 meeting in Rockville, Md.)Part II, Page 11-128 for the floor elevations for zone 331 versus zone 330. They should bethe same.El-34 ENCLOSUREIResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"TVA Response:TVA agrees the as-designed FPR sent on August 15, 2011, incorrectly lists these elevationsas different. The elevations for the Pipe Chase, Unit 1 and Unit 2 should be the same andthey should be Elevation 676, Elevation 692, and Elevation 713. The FPR, Part II will berevised to correct the elevations for Zone 331 on page 11-128, and this revision will besubmitted in the next FPR.29. NRC Question (Received during August 31, 2011 meeting in Rockville, Md.)In the August 5, 2011 submittal, Question VI-7. 1, TVA provided clarifying information for theUnit 2 Reactor Building compartmentation. TVA needs to fix the description of the Unit IReactor Building in the FPR.TVA Response:TVA will update the description of the Unit 1 Reactor Building in the next FPR submittal.30. NRC Question (Received during August 31, 2011 meeting in Rockville, Md.)Part VII, Section 3.1.1 -In room 674. O-A 1, Waste Holdup -Clarify what is meant by"required for auxiliary control?"TVA Response:Cables that are only required for a fire in the Auxiliary Control Room are called auxiliarycontrol circuits. The circuits in room 674.0-Al are auxiliary control circuits and are notrequired for a fire in this room.31. NRC Question V1I-26 (Received in email dated September 20, 2011 from NRC [JustinPoole [NRRl)The text of Part VII, Section 2.4, "Intervening Combustibles, " indicates that this deviation isfor the Auxiliary building. However, the reviewers have identified two instances of relianceon this deviation for areas outside of the Auxiliary Building.[1] Table I-1 lists Deviation 2.4 for Fire Area 53, Diesel Generator building (page 1-12) andfire Area 60, IPS[2] These are also reflected in Part 3.59 (Diesel generator Building) and Section 3. 66, (iPS).Section 3.59 was revised to include crediting the deviation for the 8/15/11 version of theFPR.The deviation should be revised to reflect all of the areas that it is relied upon.E1-35 ENCLOSURE1Response to NRC's Round 6 Request for Information Regarding "Fire Protection Report"TVA Response:[1] The Diesel Generator Building is not part of Deviation 2.4. Table I-1 will be revised todelete this reference in the next FPR submittal. The IPS does rely on this deviation andis addressed in previous question VII-21.1.[2] Part VI, Section 3.59 will be revised to delete the reference to Part VII, Section 2.4 andwill be included in the next FPR submittal.The deviation in Part VII, Section 2.4 will be revised to address the IPS and will beincluded in the next FPR submittal (see question VII-21.1).32. NRC Question 11-48 (Received in email dated September 20, 2011 from NRC [JustinPoole, NRR1)[1] The information used to create the SSER 18 section 3.1.4.2 "Internal conduit FireBarrier Penetration Seals" currently exists only in an RAI response from July 1, 1994(ML072320559) and not in the FPR. In order to achieve a cleaner licensing basis, it wouldbe appropriate to include this information in the FPR.[2] Additionally, there is a conflict regarding the combustibility of the seal material betweenthe RAI response and the internal conduit seal definition in Part II of the FPR.TVA Response:[1] The following information from the July 1, 1994 RAI response describing therequirements for internal conduit seals will be added to Part II, Section 12.10.6.B in thenext revision of the FPR:A 1-hour, 2-hour, or 3-hour rating in accordance with IEEE 634-1978, section 6.1was established for electrical penetration seals. Transmission of heat throughthe penetration seal was limited to 7000 F or the lowest auto-ignition temperatureof cable in the penetration, whichever is lower.Conduit penetrations typically require only internal seals since most conduitpenetrations were poured-in-place during plant construction. Internal sealmaterials, design, and locations in walls and floor/ceiling assemblies have beenevaluated as equivalent to tested configurations. If a conduit requires an externalseal (e.g., the conduit passed through a sleeve larger than the conduit), theexternal seal will meet the same criteria as stated in the above paragraph.The criteria for internal conduit seals that were reviewed and approved by theNRC are based on the information presented in an RAI response from July 1,1994 (ML072320559). The following information is from that submittal.E1-36 ENCLOSUREIResponse to NRC's Round 6 Request for Information Regarding "Fire Protection Report"The internal conduit seal criteria is documented on drawing series 45W883 andis as follows.Smoke and gas seals shall have a (min) 3 inch RTV silicone foam and 1 inchceramic fiber damming at the bottom/back side of the foam. The fiber dammingmay or may not exist in the front/top side of the foam. The silicone foam shall beinstalled at the first available opening. Conduits that terminate in junction boxesor other non-combustible enclosures need not additional sealing except forAuxiliary Building secondary containment envelope boundaries. See table belowfor sealing instructions. A closed electrical cubical similar to a motor controlcenter or switchgear cabinet is not considered a non-combustible enclosure.CONDUIT TOTAL LENGTH OF CONDUIT FROM BARRIERSIZE CONTINUOUS <1' >1'- >3' ->5' ->22'THRU AREA <3' <5' <22'_ -<1" NSR F NSR NSR NSR NSR1" NSR F S S NSR NSR>1"- <2 NSR F S S NSR NSR2" NSR F F s4 NSR NSR>2" -<4" NSR F F F4 S4 NSR>4" NSR F F F S NSRNotes:1. NSR -No Seal Required2. S -Smoke and Hot Gas Seal Required3. F -Fire Seal Required4. NSR if cable fill exceeds 40%[2] The definition of Internal Conduit Seals, Smoke and Hot Gas Seals in Part II, Section 5.0,will be revised to delete the reference to non-combustible material and will be included inthe next FPR submittal. The new definition is as follows:"Smoke and Hot Gas Seals -Seals installed inside conduit openings to prevent thepassage of smoke and hot gasses through fire barriers. These seals may be locatedat the fire barrier or at the nearest conduit entry on both sides of the fire barrier.Smoke and hot gas seals are not required to have a fire resistance rating equal tothe fire barrier in which they are installed."E1-37

Enclosure

2Summary Listing of Fire Protection Commitments1. The corrections identified in Letter Item # I (NRC Question RAI FPR General-7),subsection [1] will be submitted in the next FPR.2. A review of the FPR has been performed to identify and correct similar deficiencies thatoccurred when modifying the FPR to align with past RAI responses. The deficienciesthat were identified during this review will be submitted in the next FPR. A summarytable of the identified deficiencies is included in Attachment 1. [Letter Item # 1. NRCQuestion (RAI FPR General-7) subsection [2113. The corrections identified in the FPR Part VI, Section 3.26.1, subsection [1] and Part I,Table I-1, subsection [2] will be submitted in the next FPR. [Letter Item # 2. NRCQuestion (RAI FPR General-8) subsection [1] and [2]]4. FPR, Part I, Table I-1 will be corrected to reflect that no OMAs or repairs are required fora fire in rooms 713.0-Al0, 713.0-A17 and 737.0-A10 and will be submitted in the nextFPR submittal. [Letter Item # 3. NRC Question (RAI FPR 1-3) subsection [1]]5. A review of the FPR has been conducted for consistency between sections. Identifieddiscrepancies have been corrected and will be included in the next FPR submittal.[Letter Item #s 1,2 & 3]6. FPR, Part II, Section 14.1.2.b will be revised to specify that the section applies only toinaccessible areas outside of containment, as defined by the FPR, Part II, Section 5.0.[Letter Item # 4. NRC Question (RAI FPR 11-37.1.1)]7. The changes contained in Letter item # 7 [NRC Question (RAI FPR 11-46)] will besubmitted in the next FPR.8. The changes contained in Letter item # 8 [NRC Question (RAI FPR 11-47)] will besubmitted in the next FPR.9. Part V, Section 2.2.2 of the FPR will be submitted in the next FPR submittal. [Letter item# 9. NRC Question (RAI FPR V-13.1)]10. The fire detection system provided for 692.0-Al B does not extend into the tunnel.Section 8.3.3.2 will be revised to clarify that the tunnel from 692.0-Al B is not providedwith detection or automatic suppression. This change will be submitted in the nextrevision to the FPR. [Letter item # 12. NRC Question (RAI FPR VI1-18)]11. The revisions to the FPR that were discussed in Letter Item # 13 [NRC Question (RAIFPR VII-19)] will be added as parts of new Section 3.1 in the next FPR submittal. Inaddition, an extent of condition review has been performed for this item, and the resultswill be included in the next revision of the FPR.12. The changes contained in Letter item # 14 [NRC Question (RAI FPR VII-20)] will besubmitted in the next FPR.E2-1

Enclosure

2Summary Listing of Fire Protection Commitments13. The Engineering Evaluation documented in Part VII, Section 4.5 will be revised toprovide additional justification for the lack of detection in the Refueling Room and NewFuel Storage Vault and this will also eliminate the need for the OMAs. Therefore,Part VII, Section 8.3.44 is being deleted. These changes to the FPR will be included inthe next FPR submittal. [Letter item # 15. NRC Question (RAI FPR VII-21)]14. TVA confirms there will be procedures for each affected room that address each OMA.The OMAs identified in the FPR are to be verified by walkdowns and documented inAOI 30.2 prior to fuel load. The statement that a room does not have dedicatedprocedures for fire safe shutdown will be deleted for the evaluations. These revisedevaluations will be included in the next FPR submittal. [Letter item # 16. NRC Question(RAI FPR VII-22)]15. Engineering Evaluations will be performed for the four fire zones (2RA2 -AccumulatorRoom 2, 2RF2 -Fan Room 2, 2RIR -Instrument Room and 2RO-N -Outside Crane Wall[North]) identified in NRC's request and will be added to Part VII, Section 3.1 of the FPR.These evaluations will be included in the next FPR submittal. [Letter item # 17. NRCQuestion (RAI FPR VII-23)]16. TVA has performed a generic review for Unit 2 and identified all rooms in the Unit 2Reactor Building without detection, but contains FSSD components. Additionalinformation will be added to the next revision to the FPR to address these rooms. [Letteritem # 17. NRC Question (RAI FPR VII-23)]17. The changes addressed in Letter item # 18 [NRC Question (RAI FPR VII-24)] will be inthe next FPR submittal.18. The changes addressed in Letter item # 19 [NRC Question (RAI FPR VII-25)] will besubmitted in the next FPR.19. Part VII, Section 2.4 will be revised to include the oil filled transformers and will beincluded in the next FPR submittal. [Letter item # 20. NRC Question (RAI FPR VIII-21.1)]20. With regard to "This summary information would be appropriate to include in the FPR atthe correct level of detail," the following revision to Part II, Section 7.7 will be included inthe next FPR:The Fire Protection Program, uses the applicable parts of the TVA Nuclear QualityAssurance Plan (TVA-NQA-PLN89-A) to manage the audit frequencies. This QAprogram is further described in corporate standards and implementing procedures.Any changes to the NQAP are controlled under 1OCFR50.54(a). [Letter Item #23,NRC Question (RAI FPR 11-26.1)]21. A review of Part VII, section 8 has been performed and the section has been revised toreplace "fire room" with "room." The change will be included in the next revision to theFPR. [Letter item # 24. NRC Question (Received during Au.gust 31, 2011 meeting inRockville, Md.)]E2-2

Enclosure

2Summary Listing of Fire Protection Commitments22. A review has been performed to change automatic action sprinklers to automaticsprinklers. The change will be included in the next revision to the FPR. [Letter item #25. NRC Question (Received during August 31, 2011 meeting in Rockville, Md.)]23. The changes addressed in Letter item # 26 [NRC Question (received during August 31,2011 meeting in Rockville, Md.)] will be submitted in the next FPR.24. The FPR, Part II, Section B.14.3.1 .a will be revised and submitted in the next FPRsubmittal. [Letter item # 27. NRC Question (received during August 31, 2011 meeting inRockville, Md.)]25. The FPR, Part II will be revised to correct the elevations for Zone 331 on page 11-128and this revision will be included in the next FPR submittal. [Letter item # 28. NRCQuestion (received during August 31, 2011 meeting in Rockville, Md.)]26. TVA will update the description of the Unit 1 Reactor Building it will be in the next FPRsubmittal. [Letter item # 29. NRC Question (received during August 31,2011 meeting inRockville, Md.)]27. The changes addressed in Letter item # 31 [NRC Question VII-26 (received duringSeptember 20, 2011 NRC email)] will be submitted in the next FPR.28. The information from the July 1, 1994 RAI response describing the requirements forinternal conduit seals will be added to Part II, Section 12.10.6.B in the next revision ofthe FPR. [Letter item # 32. [NRC Question 11-48 (received during September 20, 2011NRC email)]29. The definition of Internal Conduit Seals, Smoke and Hot Gas Seals in Part II,Section 5.0, will be revised to delete the reference to non-combustible material and willbe included in the next FPR submittal. [Letter item # 32. [NRC Question 11-48 (receivedduring September 20, 2011 NRC email)]E2-3 ATTACHMENT IIncorporation of RAI Responses into FPRResults of ReviewRAI Letter RAI FPR Section Add Section to Be COMMENTSGroup date ID (Y/N) Revised Revised2 03/16/11 V-4 Y V-2.4.2 V-2.4.2 Remove "or Part V, section 2.1.2.2.dless" talks about "OMAs to beperformed in the fireaffected room in about anhour OR LESS are..."This is consistent with thereviewers concern about"Less than 2 hours."2 03/16/11 V-6 Y V-2.4.3, VII-7.1.3, 7.2.1, Update these sections toTable I-1 7.2.2 agree with the currentOMAs.2 03/16/11 V-9 Y V-2.4.3, VII-7.211 Text in V-2.4.3 deleted byTable I-1 later revision -contentpertaining to combustibleloading for 729-AlO thatwas to have been deletedis now in part VII-7.2.1.See V-6 above. Sections7.1.3.1, 7.2.1, and 7.2.2will be reconciled to agreethe the current OMA set.2 03/16/11 11-8 Y 11-13.0, See response to14.1, Group 7 Question 1B. 14.1, FPR-General-7B.14.2,B.14.3,B.14.4,B.14.82 03/16/11 VII-1 Y VI-3.15.3 VI-3.15.3 VI-3.15.3 now containsthe statement "Thiseliminates the need forDeviation 4.7 in Part VII."but the change removedDeviation 4.7 so there isno longer a para. 4.7.3.15.3 should say there isno need for a deviation. RAI Letter RAI FPR Section Add Section to Be COMMENTSGroup date ID (Y/N) Revised Revised2 03/16/11 VIII-1 N 111-10.3.1.e(3) 111-10.3.1.e(3) should beVII -2.6.3 revised to clarify somenew cables may not bequalified to IEEE-383.Also VII -2.6.3 should beclarified as not all nonIEEE-383 qualified arecoated with a fireretardant material, i.e., 9or less in a tray isallowed.3 05/06/11 11-13 Y Part II, See response to Part Ill, Section 4.7 stillSection Group 7 Question 1 says, "Unit 1" and was not14.3.1.b. 1; FPR-General-7 revised to include bothTable 14.3; units. RemainderPart Ill, incorporated.Section 4.7;Part IV,Section 3.33 05/06/11 111-13 Y Part Ill, See response to Part Ill, Section 4.7 stillSection 4.7; Group 7 Question 1 says, "Unit 1" and was notPart II, FPR-General-7 revised to include bothTable 14.3, units. Remainderitem 14.3.c; incorporated.Part IV,Section3.3;Part II,Section14.3.1.b.13 05/06/11 IV-3 Y Part III, See response to Part III, Section 4.7 stillSection 4.7; Group 7 Question 1 says, "Unit 1" and was notTable 14.3, FPR-General-7 revised to include bothitem 14.3.c; units. RemainderPart IV, incorporated.Section3.3;Part II,Section14.3.1.b.1 RAI Letter RAI FPR Section Add Section to Be COMMENTSGroup date ID (YIN) Revised Revised4 05/26/11 VII-2 Y VIII-3.3 VII page 33 The RAI indicated SR(3) 375516 was initiated tocorrect Part VIII, Sect. 3.3to state there are threerather than four standpipesystems. The responseshould have said Part VII,Section 3.3. Thiscorrection will be in thenext FPR submittal.4 05/26/11 VIII-3 Y B.1 X-3.1.2 Title of NFPA-4A wasinadvertently changedfrom "... Fire Department"to ".. Fire Brigade." Thiswas correct in the May2011 FPR submittal. Thetitle of NFPA-4A in Part X,Section 3.1.2 will also becorrected in the next FPRsubmittal.4 05/26/11 VIII-7 Y D.5 D.5 "Guidelines" We changed"Guidelines ..communications" to"communication" in5/18/11 submittal. Typistadded "s" back in 8/15/11FPR submittal. The "s"will be deleted in the nextFPR submittal.6 08/05/11 II- Y 14.1.1, See response to37.1 14.1.2, Group 7 RAI-II-B14.1.1, 37.1.1 follow upB14.1.2 question6 08/05/11 111-15 Y 4.2.66 4.2 (add looked for calcs referredWBPEVAR9205004, to in text but notEPM-BFS-041895, referenced in section 4;EPM-BFS-053195, found 4.EPM-BFS-063095)6 08/05/11 Vl- Y table 3.3 3.67.3.2 thru Make same changes for7.1 VI 3.84.3.2 3.67.3.12 Unit 1 reactor buildingthru AV-0923.84.3.126 08/05/11 VI-9 Y AV-091 & 11-4.2 Add calculationAV-117 WBPEVAR9602001 toreferences in Part II, RAI Letter RAI FPR Section Add Section to Be COMMENTSGroup date ID (YIN) Revised Revisedsection 4.26 08/05/11 VI-10 Y AV-092A-L 11-4.2 Add calculation& AV-1 18A- edq00099920110005 toL references in Part II,section 4.2 ATTACHMENT 2DGB Roof Hose Stations 0-ISV-26-565 & -566 Graph13012011010090soo90807060-A-08/22/1995I -08/31/1996I,,+ -11/14/1997-,0-06/10/2001-.-06/23/2004-o-01/18/2008-X-05/02/20101 2 4 8 16 32 64 128 256 512Flow (gpm)

Attachment

3 Redacted ATTACHMENT 4Dow Corning 561 Silicone Transformer LiquidTraining Manual Dow Corning 561Silicone TransformerLiquidTechnical Manual The information and data contained herein are based on information we believereliable. You should thoroughly test any application and independently concludesatisfactory performance before commercialization. Suggestions of uses should not betaken as inducements to infringe any particular patent.Copyright 0 1994, 2006 Dow Corning Corporation. All rights reserved. 561J Transfonner Flid Technical ManualPrefaceWe hope this technical manual will help you discover for yourself the advantages of using atransformer filled with Don, Corningg 561 Silicone Transformer Liquid. The information onproven performance, fire safety, humnan and environmental safety, recyclability, and costeffectiveness all indicate that Dow Corning@ 561 Silicone Transformer Liquid offers significantbenefits over other types of liquid-filled and dry-type transformers.Dow Corning 561 Silicone Transformer Liquid is backed by Dow Coming Coiporation, whichhas a team of technical specialists around the world specifically committed to Dow Corning561 Silicone Transformer Liquid. That means if you ever have a question or a problem, you'llalways get an answer-and a solution.i Dow Coming 561 Silicone Transformer Liquid TeclntcalManuarTable of ContentsPreface .............................................................................................................................................. iTable of Contents ............................................................................................................................ iiSection 1: G eneral Inform ation ...................................................................................................... 1-11.1 W hat Is a Silicone Fluid? ................................................................................................. 1-11.2 Selecting a N ew Transformer ......................................................................................... 1-21.3 W hy a Liquid-Filled Transform er? .................................................................................. 1-21.4 W hy a Silicone Liquid? ................................................................................................... 1-51.5 Bibliographic Resources .................................................................................................. 1-7Section 2: Safety ............................................................................................................................... 2-12.1 M aterial Safety D ata Sheet .............................................................................................. 2-12.2 Health and Environm ental A spects .................................................................................. 2-22.2.1 Toxicology ................................................ 2-22.2.2 Environm ental Toxicity ......................................................................................... 2-22.2.3 Environmental Entry ......................................... 2-32.2.4 Environm ental Fate and Effects ............................................................................. 2-32.3 Regulatory Facts .............................................................................................................. 2-42.4 Spill Inform ation ............................................................................................................ 2-52.4.1 M inor Spills ........................................................................................................... 2-52.4.2 Spills on W ater ....................................................................................................... 2-52.4.3 Spills on Roadways ............................................................................................... 2-62.4.4 Spills on Soil .......................................................................................................... 2-62.4.5 Recom m ended Absorbents .................................................................................... 2-62.4.6 Spill Containm ent ................................................................................................. 2-82.5 Fire Safety ........................................................................................................................ 2-92.5.1 Pool-Fire Burning Characteristics ......................................................................... 2-92.5.2 Extinguishm ent .................................................................................................... 2-112.5.3 Threat to Adjacent Buildings ................................... 2-112.5.4 Sm oke and Combustion Products ........................................................................ 2-122.5.5 Basic Theim ochemical Properties ....................................... .......................... 2-122.5.6 UL Fact-Finding Report ....................................................................................... 2-12Section 3: Transform er Design Inform ation ............................................................................ 3-13.1 D ielectric D ata ................................................................................................................. 3-I3.1.1 Dissipation Factor, Df ........................................ 3-13.1.2 D ielectric Constant, D K ......................................................................................... 3-33.1.3 Electrical Breakdown ............................................................................................ 3-33.2 Therm al Capabilities ........................................................................................................ 3-63.3 Pressure Increases ....................................................................................................... 3-83.4 Paitial Discharge Characteristics ........................................... 3-93.5 Load-Break Switching Performance .............................................................................. 3-10ii 5617 Transfaorer Fluid Technical Mannai3.6 Medium and Large Power Transformer Applications ................................................... 3-113.7 M aterial Com patibility ................................................................................................... 3-123.8 Physical Characteristics ................................................................................................. 3-143.8.1 V apor Pressure ..................................................................................................... 3-143.8.2 V olum e Expansion ............................................................................................... 3-143.8.3 Solubility of Gases ............................................................................................... 3-163.84 V iscosity-Temperature Relationship ................................................................... 3-173.8.5 Specific H eat ................................................................................................... 3-183.8.6 D ensity ............................................................................................................. 3-183.9 Lubricity ........................................................................................................................ 3-193.10 Retrofill Considerations ................................................................................................. 3-213.10.1 M aterial and Component Compatibility ............................................................. 3-213.10.2 Tem perature Rise/Heat Transfer ......................................................................... 3-213.10.3 Fire Safety Considerations ................................................................................... 3-24Section 4: Specifying 561 Transform er Fluid ................................................................................ 4-14.1 M odel Specification ......................................................................................................... 4-14.2 Applicable Standards ....................................................................................................... 4-54.2.1 1996 N ational Electrical Code ............................................................................... 4-54.2.2 1996 N ational Electrical Safety Code ................................................................... 4- 64.2.3 A STM Standards .................................................................................................... 4- 74.2.4 IEEE Guide ............................................................................................................ 4-74.3 Product Listings ............................................................................................................... 4-84.3.1 Factory M utual Approval ....................................................................................... 4-84.3.2 UL Classification M arking .................................................................................... 4-8Section 5: M aterial H andling .......................................................................................................... 5-15.1 Storage ............................................................................................................................. 5-I5.2 Bulk Handling .................................................................................................................. 5-25.3 Sampling .......................................................................................................................... 5-25.3.1 Sampling from Shipping Containers ...................................................................... 5-25.3.2 Sampling from Apparatus ...................................................................................... 5-55.4 Pum ping ........................................................................................................................... 5-65.5 Filling Transformers ........................................................................................................ 5-75.5.1 Filling under V acuum ............................................................................................ 5-75.5.2 Filling without Vacuum ......................................................................................... 5-75.6 V acuum D egasification .................................................................................................... 5-95.7 Silicone Solutions for M ineral Oil Foam ing .................................................................. 5-115.8 Paint and Paintability ....................................................... ..................................... ... 5-135.8.1 Surface Preparation .............................................................................................. 5-135.8.2 Paint A dditives .................................................................................................... 5-14Section 6: M aintenance ................................................................................................................... 6-16.1 Periodic Inspection and Testing ....................................................................................... 6-1nli Dow Corning .561 Silicone Transformer Liquid Technical Manual6.1.1 V isual Inspection ................................................................................................... 6-26.1.2 D ielectric Strength (ASTM D877) ........................................................................ 6-26.1.3 W ater Content ....................................................................................................... 6-46.1.4 Gas Evolution/AMe Behavior ...................................... 6-46.2 Contamination .............................................. 6-76.2.1 Contamination with W ater ..................................................................................... 6-76.2.2 Contam ination with Particulates ......................................................................... 6-106.2.3 Contamination with M ineral O il .......................................................................... 6-106.3 Filtration ......................................................................................................................... 6-116.3.1 Rem oval of Particulates ....................................................................................... 6- 116.3.2 Filtration to Reduce W ater Content .................................................................... 6-116.3.3 Filtration Equipm ent ...................................................................................... 6-126.4 Leaks .............................................................................................................................. 6-136.5 Reuse, Recycle, or Disposal of Silicone Transformer Fluid .......................................... 6-146.5.1 Recycling ............................................................................................................. 6-146.5.2 Incineration and Landfill .................................................................................... 6- 156.5.3 Reprocessing and D isposal Services .................................................................... 6- 156.6 IEEE Guide Availability ............................................................................................... 6-18iv Section 1: General informatlonSection 1: General InformationSection Content1.1 What Is a Silicone Fluid? ....................................... 1-11.2 Selecting a New Transformer ......................................................................................... 1-21.3 W hy a Liquid-Filled Transformer? .................................................................................. 1-2Performance W ithout Extra Cost ..................................................................................... 1-2Size and W eight .............................................................................................................. 1-3Quiet ................................................................................................................................. 1-4Predictable Performance ................................................................................................. 1-41.4 W hy a Silicone Liquid? .................................................................................................. 1-5A Pure Synthetic Material ................................................................................................ 1-5Fire Safety Indoors or Outside ......................................................................................... 1-5Stability Leads to Long Life and Lasting Performance ................................................... 1-5W idespread Acceptance ................................................................................................... 1-61.5 Bibliographic Resources .................................................................................................. 1-7How To Use These Bibliographic Resources .................................................................. 1-7General Properties ........................................................................................................... 1-7Perfornmance and Service Life .......................................................................................... 1-7Fire Safety ........................................................................................................................ 1-8High Voltage Strength .................................................................................................... 1-9W ater Contamination ...................................................................................................... 1-9Environmental ......................................................................................... 1-9Toxicological .............................................. 1-10Codes and Standards ...................................................................................................... 1-101.1 What Is a Silicone Fluid?Silicone fluids are a family of synthetic liquids having the molecular structure shown below, inwhich the groups identified as methyl groups may represent any organic group. The organicgroups can be all the same or different. The value of n determines the molecular weight of thesilicone fluid, which in turn determines its viscosity.L" nQ Oxygen atoms4 R Methyl 1Repeating unit enclosed in brackets1-1 Dow Corning* 561 Silicone Transformer Liquid Teclnical ManualPolydimethylsiloxane (PDMS) fluids are thermally stable, chemically inert, essentially nontoxic,and water repellent. The viscosity of the commercial products varies from 0.65 to 2,500,000centistokes (cSt). These fluids remain fluid over a wide range of temperatures, even though thevalue of n can vary from 0 to 2,000 or more. Other physical and electrical properties exhibitrelatively small variations with temperature.Silicone fluids are used as lubricants, mold-release agents, dielectric coolants, antifoam agents,and heat-transfer fluids. Because of their unique surface properties, low toxicity, and thermal andchemical stability, they are used in small concentrations in car polishes, paints, and cosmetics.Dow Corning 561 Silicone ITransformer Liquid is a 50 centistoke viscosity PDMS product, inwhich all the organic groups are methyl groups, CH3.It is water-clear, nongreasy, and virtuallyodorless, with good insulating and dielectric properties.1.2 Selecting a New TransformerSelecting the best transformer for a given application might seem like a difficult task, but with theright information-backed by proven applications and 20 years of testing-a difficult decisioncan be made easy.There is a variety of transformer types from which to choose, including air-cooled dry-type, cast-resin, and liquid-filled transformers. Liquid-filled transformers can contain mineral oil,chlorinated hydrocarbons, high molecular weight hydrocarbons, or silicone fluid. Depending onthe needs of your application, each type offers distinct advantages. But many also havedrawbacks. The key is to decide which engineering and operating compromises are acceptableand estimate the long-term effects they will have on your application.We believe the information in the following pages will help you select which type of transformerwill work best for you and which should be avoided for your application.1.3 Why a Liquid-Filled Transformer?Liquid-filled transformers were developed more than 90 years ago. Today, many users continueto prefer this design over dry-type transformers, especially for demanding applications such asnetworks and medium and large power transformers. There are several important reasons for thispreference.* Unlike solids, liquids cool as well as insulate. As a result, you can select a liquid-filled transformerthat is more compact than a comparable dry-type or cast-resin type.* Liquid-filled transformers provide high efficiency and high BiL at reasonable cost. Similarelectrical performance can be obtained from dry-type or cast-resin transfoImers-but usually onlyat additional cost.Peifornance Without Extra CostThe high dielectric strength of liquid-filled transformers provides greater design flexibility. As aresult you can optimize the design to meet specific load requirements and thereby reduceoperating costs. For example, beginning with a liquid-filled system, you can design a small,compact core transformer that delivers a very high BMb and very low no-load losses. You can1-2 Section 1: General Informationachieve a combination of operating economy, reliability, and small size that is not practical withdry-type and cast-resin transformers. Table I- I compares the BIL rating of dry-type transformersto liquid-filled transformers.Table 1-1. Typical temperature rise and BIL ratings for transformersAverage windingTransformer type temperature rise OIL ratingLiquid filled 55/650C 95 kVDry 1500C 60 kVLiquid systems also have an advantagestemming from their superior ability to removeheat from the core and coil assembly. Thisresults in greater overload capacity andcorresponding savings in maintenance andoperating costs, as well as longer insulation life.This is especially true for silicone-filledtransformers because silicones have the highestthermal stability of all available liquids. Long-term costs resulting from energy loss in a unitcan exceed the capital costs of purchasing thetransformer. As a result, it is very important toevaluate the rate of loss and select the bestdesign for your load and service conditions..J!UL99.299.098.898.698.498.2liquidcast,Ill025 50 75Percent of Rated Load1 0Figutre 1-1. Typical efficiency for major types offransfonnersTo provide for load growth or emergency loading, transformers are usually designed to handlemore than the expected initial load. A loss evaluation is based on average transformer loading.Figure 1-1 shows that liquid-filled transformers are more efficient, particularly at low load levels.Size and WeightTable 1-2 shows a dimension and weight comparison of liquid-filled, dry-type, and cast-coiltransformers with different temperature rises.Table 1-2. Dimensions and weights of 1000 kWA, 13.8 kV- 480 V transformer3Liquid-filled Conventional dry type Cast coilTemperature rise 650C 1500C 800C 800CHeight 65.0 in. 90.0 In. 100.0 In. 90.0 In.Width 58.5 in. 78.0 in. 84.0 In. 84.0 In.Depth 74.5 in.? 58.0 in. 70.0 In. 54.0 In.Total weight 6980 lb 5830 lb 8500 lb 7500 lb"References from transformer manufacturers datab Includes depth of radiators1-3 Dow Corning8 561 Silicone Transfonner Liquid Teclnical ManualQuietM 70Whether indoors or near buildings and people, -'5 65loud or overbearing noise can be an .environmental nuisance. Dry-type transformers, "2 60in general, aren't known to be quiet. Liquid- _filled transformers, because of their insulation, "M.,r 55are the quietest transformers available. Figure 1-2 shows maximum average sound levels. 50Silicone-filled Dry-typePredictable Performance Transformer TransformerFigure 1-2. Maximum aver~age sound levels forOne reason liquid-filled transformers are more tFi ree-phasa substation-type transformersreliable than dry types is because they can bediagnostically tested, providing important predictive information to transformer owners. Periodictesting of water content, breakdown strength, and dissolved gas composition can help avoidcostly, unplanned outages and catastrophic failures by detecting leaks, low-level arcing, and otherinsulation problems before they develop into serious situations. See Section 6.1 for details ondiagnostic tests for silicone-filled transformers.Liquids don't crack or form voids under extreme temperature variations, so you can expect longservice life. Plus, liquid-filled transformers are sealed so they can operate in many harshenvironments without special housings. They also reduce maintenance costs by eliminating theneed for and inconvenience of annual shutdowns for cleaning. All in all, liquid-filled transformersare reliable and efficient suppliers of modern power requirements.1-4 Section 1: General Informafion1.4 Why a Silicone Liquid?Most liquid-filled transformers are filled with mineral oil. The primary drawback of mineral oil isthat it can present an unacceptable fire risk when used in or near buildings. With silicone fluid,you can meet code requirements without the expense of special vaults and/or fire protection. Yougain the reliability and efficiency of liquid-filled design even when the transformer must belocated close to the load, indoors, or near buildings. See Section 4.2 for details on coderequirements.Dow Coming began investigating silicone fluids as potential dielectric coolants in the 1950s. Theinvestigation resulted in the development and production of Do011 Corning@ 561 SiliconeTransformer Liquid, which is now widely used to provide excellent performance in liquid-filledtransformers, especially where fire safety and thermal stability are required.A Pure Synthetic MaterialDow Corning 561 Silicone Transformer Liquid contains no chlorine or other halogens. It is apure polydimethylsiloxane material that contains no additives, such as pour-point depressants orthermal stabilizers. Similar silicone fluids are used in cosmetics and as food additives. It is com-patible with materials used in the construction of transformers, nonvolatile, thermally stable, andchemically inert. This compatibility and stability are instrumental in prolonging transformer lifeand reducing maintenance.Fire Safety Indoors or OutsideDow Corning 561 Silicone Transformer Liquid presents a much lower fire hazard than othertransformer fluids. It is difficult to ignite, but if it should ignite, it produces less heat and smokeand virtually extinguishes itself when the external source of heat is removed. Dow Corning 561Silicone Transformer Liquid is Underwriters Laboratories, Inc. (UL) classified and FactoryMutual Research Corporation (FM) approved as "less flammable" per NEC 450-23. In addition,tests have shown that the toxicity of combustion byproducts from Dow Corning 561 SiliconeTransformer Liquid is lower than other conunonly used insulating materials, such as highmolecular weight hydrocarbons or mineral oil, as well as epoxies, phenolics, polyesters, and otherdielectric materials used for transformer construction. See Section 2.5 for details on fire safety.Stability Leads to Long Lyfe and Lasting PeiformanceThe thermal stability of silicone also improves performance while reducing the need for fluidreprocessing during use. Dow Corning@ 561 Silicone Transformer Liquid will not form sludgeand/or acidic byproducts, even at elevated operating temperatures. See section 3.2 for details onthe thermal capabilities of silicone fluid. Figures 1-4 and 1-5 show how dissipation factor anddielectric strength change as common transformer fluids age at elevated temperatures.1-5 Dow Corming 561 Silicone Transformer Liquid Tec/micalManital0.050S--O--Sfto.. (St0.040 U.-O'-',nu(Set)o M~Aineral o#l(Set 1)I----i-neral all (set 2)um 0.030.1 0.020ra0 .7 30 60Time, daysFigure 1-4. Change in dissipation factor ofsiliconefluid aging compared tomineral oil.Widespread Acceptance-rUrCtoaaaai5048464442403836340 7 30 60 90Time, daysFigure 1-5. Change in dielectric strength ofsilicone fluid aging compared tohigh molecular weight hydrocarbonsSince 1974, Dow Corning 561 SiliconeTransformer Liquid has been accepted byutilities and commercial property owners aswell as industries ranging from food pro-cessing and pharmaceuticals to mining,paper mills, and transportation. In fact, asurvey of utilities (Figure 1-4) found thatwhen askarel-filled transformers arereplaced, nearly 91% of those units are beingreplaced with silicone-filled units, comparedto 8.6% for R-Temp* fluid and 0.3% for dry-type transformers.IV- Dry lypeFIgilre 1-6. Askarel fire-safe transforner replacementchoices (Source: 1987 utility analysis follow-npsurvey wherefire-safe transformers ivere used.)With over 100,000 silicone-filled units in operation worldwide and more than 20 years ofpractical operating experience, Dow Coming is not aware of any transformer filled with DowCorningg 561 Silicone Transformer Liquid that has failed to carry the load required forsatisfactory performance.In short, Dow Corning 561 Silicone Transformer Liquid has performed as expected-noproblems caused by the liquid have ever been reported. In fact, even in rare cases where severefailure of protective devices has exposed the fluid to prolonged arcing and ignited the fluid, nothermal damage due to the fluid bturing has occurred.'R-Temp is a registered nmdemaik of Cooper Power Systems, Inc.1-6 Section ): GeneralInfoarnation1.5 Bibliographic ResourcesDow Corning Corporation has prepared a number of informational brochures, booklets, andtechnical articles to help you use Dow Coming 561 Silicone Transformer Liquid safely andefficiently. Following is a list of these resources, many of which can be ordered by contactingyour Dow Coming representative. Others resources mentioned can be obtained directly fromIEEE, ASTM or listing agencies such as Factory Mutual or Underwriters Laboratories.How To Use These Bibliographic ResourcesWe believe the technical information contained in these reports is accmuate even though specificreferences may be to codes and standards or regulatory requirements that have changed since thetime of writing. Information on current requirements relative to transformer fluid is availablefrom Dow Coming. Please contact your local Dow Coming representative or call 1-800-HELP-561 (in the USA) if needed.General PropertiesG1. "Dielectric Properties of Silicone Fluids," Hakini, R.M., IEEE Conference, Paper #C74-262-2. Lit.no. 10-255G2. "Structure Property Relationships in Silicone Fluid Dielectrics," G. Vincent. G. Fearon, T. Orbeck,Annual Report, Conference on Electric Insulation and Dielectric Phenomena, 1972, pp. 14-22, CA79 (8), 43156d. Lit. no. 10-256G3. "Environmentally Acceptable Insulating Fluids May Replace Askarel." D. Duckett, RTE Corp.,General Meeting of Transmission and Distribution Committee, Edison Electric Institute, May 8,1975G4. "Small Power Transfonner Alternatives," S. Mort and W.H. Bishop, Canadian Electricity Forum,April 1992. Lit. no. 10-519AG5. "A Comparison of Non-liquid Power Transformers with Silicone-filled Units." J. Goudie. DowCorning. Lit. no. 10-512G6. "Silicone Materials for Electrical Insulation that Yield Low Heat Release Rates and Low Levels ofToxic Products During a Fire," E.A Reynaert, and W.C. Page. Environmentally Friendly FireRetardant Systems Conference, Sept. 22-23. 1992. Lit no. 10-534G7. "Silicone As a PCB Replacement Fluid." J. Goudie, Dow Corning Corp., 5th Annual Industry &PCBs Forumr, Canadian Electricity Forun, Vancouver, B.C., Jume 1991G8. Dow Coming Dielectric Liquids for Power TransformersG9. Dielectric Properties of Dow Coining Silicone Fluids, Lit. no. 22-328G10. "Less Flamunable Transforner Liquids Gain Acceptance," CEE Neuis, February 1993. Lit. no. 10-544GIl. "Performance Testing of Silicone Transformer Coolant Using 25 kVA Distribution Transformers:Test Facility," D.F. Christianson and F.C. Dall, Dow Cornihg Corp.Performance and Service LifePl. "Performance and Safety Capabilities of Silicone Liquids As Insulating Liquids for HV Trans-formers," W. Page and T. Orbeck,' IEEE, 24th Annual Petroleum & Chemical Industry Conference.Dallas, Texas, Sept. 12-14, 1977. Lit. no. 10-2571-7 Dow CornLng 561 Silicone Transformer Liquid Technical MlanualP2. "Service Experience and Safety with Silicone Liquid-Filled Small Power Transformers," K. Evansand T. Orbeck. 1984 Doble Engineering Client Conference, April 13, 1984. Lit. no. 10-259P3. "Silicone Transformer Liquid: Use Maintenance/Safety," R. Miller. IEEE Trans. of Ind. Appl., Vol.LA-17, No. 5, September/October 1981, Paper IPSD 79-54. Lit. no. 10-208P4. "Evaluation of the Long Term Thermal Capability of High Temp. Insulating System Using SiliconeLiquid as a Dielectric Coolant," L. Gifford and T. Orbeck, IEEE Trans. of Ind. Appl., Vol. IA-20,No. 2. March/April 1984, Paper PID 83-34. Lit. no. 10-253P5. "Liquid Filled Transformers Having Temperature Operating Capabilities," D. Voytik, IEEE, 1981.Ch 1717-8/81/0000-0203. Lit. no. 10-260P6. "Secondary Substation Transformer Selection Critical to Total System Planning," C.C. Rutledge,Industrial Poit'er Systems, June 1984P7. "Load Break Switching in Silicone Transformer Fluid," S. Mort, J. Goudie, D. Ristuccia, ElectricalManufacturing Technologies Expo, October 1993. Lit. no. 10-578.PS, "Test Results Confirm the Ability of the LBOR II Switch to Operate Properly in 561' SiliconeLiquid from Dow Coming," ABB Load Break Switch Test Confirmation, June 8, 1992P9. "High Temperature Operating Capabilities of Silicone Transformer Fluid," G. Toskey, ElectricalManufacturing Technologies Expo, October 1993. Lit. no. 10-577P10. "Interpretation of Dissolved Gases in Silicone Transformer Fluids," Lit. no. 10-593.P11. "Silicone Materials in New High Temperature Liquid Transformer Desigas," J. Gondie,Proceedings of the Electrical/Electronics Insulation Conference, IEEE, September 1997Fire SafetyFl. "Classification and Application of PCB Alternative Fluids, Confusion or Progress?" K. Linsley andT. Orbeck. Doble Conference, April 1985. Lit. no. 10-254F2. "Fact-finding Report on Flanmability of Less Flanmmable Liquid Transformer Fluids," Under-writers Laboratories Inc.. December 16, 1987F3. "Study of Explosion and Fire Hazards of Silicone Liquid Under Arc Conditions," H. Kuwahara, eta., IEEE International Symposium on Electrical Insulation, Montreal, Canada, June 1976, PaperNo. E-7. Lit. no. 10-245F4. "Fire in a Cast Resin Transformer," K. Herberich, January 1979, Brandschltu /Deutsche FeverwehrZeiting. Lit. no, 10-265FS. "Silicone Liquids in Transformers," R. Miller. Electrical Energy Management, May 1980. Lit. no.22-779F6. "Silicone Transformer in a Fire Situation." J. Dimbock, Electrotechnische Zeitschrift (ETZ), Vol.16, July/August 1984. Lit. no. 10-266*F7. Transformer Fluids, Factory Mutual Approval Guide 1993*F8. Transfolrmers, Factory Mutual Engineering Corp. Loss Prevention Data Sheet 5-4, 14-8. September1986F9. "Characterization of Transformer Fluid Pool Fires by Heat Release Rate Calorimetry," M. Kanakia,SwRI Project No. (33-5344-001, March 1979, 4th International Conference on Fire Safety, January1979. Lit. no. 22-708F10. "A Model for Combustion of Poly(Dimethylsiloxanes)," J. Lipowitz and M. Ziemelis. Journal ofFire andFlammability. Vol. 7, pp. 482-503, October 1976.Fl. "Flammability Tests of Askarel Replacement Transformer Fluids," R. Hemstreet, Factory MutualResearch, Heat Release Rate, FMRC No. 1A7R3.RC. August 1978.1-8 Section 1: General InformationF12. "Flanumability of Poly(Dimethylsiloxanes) II. Flammability and Fire Hazard Properties," 1.Lipowitz and M. Zienelis. Journal ofFire and Flanmaabili.v, Vol. 7, pp. 504-529, October 1976F13. "PCB Alternatives-An Update." K. Linsley, IEEE, 1987, CH2479-4F14. "Fire Safety Properties of Some Transformer Dielectric Liquids," J. Lipowitz, J. Jones and M.Kanakia, IEEE, 1979, Cl-i 1510-7-ELF15. "Fire Safety Upgrades in Conjunction with Mineral Oil Decontamination," J. Goudie and R. Savard.EPRI, September 1993. Lit. no. 10-580F 16. "Combustion Properties of Contaminated Dielectric Fluids as Determined in the Cone Calorimeter,"J. Goudie and R.R. Buch. IEEE/DEIS International Symposium on Electrical Insulation, Baltimore,MD, Jlme 7-10, 1992F17. Nine-minute video of fire testing performed by UL. Request 561 Transformer Fluid Video. Lit. no.10-347 (For video substantiation information, request document F2.)F18. Ten-minute video of explosion testing to gain "less flammable" UL classification. Request Explo-sion/UL video. Lit. no. 10-503 (For video substantiation information, request document C6.)High Voltage StrengthHI. "Partial Discharge Characteristics of Silicone Liquids," H. Kuwahani. et al., 1975 Winter Meeting,IEEE/Power Engineering Society. New York, Jan. 30, 1975, Paper #C75 236-5H2. "Study of Dielectric Breakdown of Kraft and Aramid Papers Impregnated with Silicone," W.Brooks and T. Orbeck, Paper E-8, 1976 IEEE International Symposium on Electrical insulation,Montreal, Canada. Lit. no. 10-290H3. "Comparative Impulse Dielectric Strength Tests of Transformer Oil and 561 Silicone Liquid,"Report ET86-138-P from Ontario Hydro, Research Division. 11/24186H4. "Surface Breakdown Test Results of Mineral Oil and Silicone Oil with Kraft Paper and NoMx,"D.O. Wiltanen. J. Goudie, and H.A. Rojas Teran; IEEE/DEIS International Symposium onElectrical Insulation, Baltimore, MD, June 7-10, 1992H5. "Impulse Strength Studies of Polydimethyl Siloxane Fluid." R.E. Miller, T. Orbeck, and J. Bosco;Presentation at the 1978 Winter meeting of the IEEE Power Engineering Society; New York, NY,1/30/75Water ContaminationWI. "Water Contamination of Silicone Filled Transformers," G. Coffman and T. Orbeck, Proceedings ofdie 15th Electrical/Electronic Insulation Conference, October 1981. Lit. no. 10-272W2. "Effects of Water and Silicone Fluids," G. Vincent. Conference on Electrical Insulation & DielectricPhenomena, Dowington, PA, Oct. 21-23, 1974. Lit. no. 10-273EnvironmentalEl. "Polydimethylsiloxane: Opinion Regarding Use as Coolants in Transformers," Federal Register,Vol. 41. No. 112. June 9. 1976, p. 23226E2. "The Environmental Fate and Ecological Impact of Organosilicon Materials: A Review." C. Frye,Health and Enviromnental Sciences. Dow Coming. Lit. no. 10-370E3. "Disposal Options for 5616 Transformer Fluid from Dow Coming," R.E. Ransom. Dow Coming.Lit. no. 10-5181-9 Dow 561 Silicone Translonner Liquid TechnicalManualToxicologicalT1. "Are There Health Risks Associated with the Use of Amorphous Silicas?" R. McCunney, CorporateMedical Director, Cabot Corp. Memo, Feb. 23, 198412. "Toxicologic Classification of Thermal Decomposition Products of Synthetic and NaturalPolymers," Y. Alarie, R. Anderson, Toxicology and Applied Phannacology, 57, 1981T3. "Report of Mortality Following Sinkge Exposure to Thermal Decomposition Products of Test Sam-ples," A. Little. Rep. C-54695, November 1985T4. "Screening Materials for Relative Toxicity in Fire Situations," C. Hilado, Modern Physics, 1977T5. "Toxicity of Pyrolysis Gases from Silicone Polymers," C. Hilado, et al, Journal of CombustionToxicology, Vol. 5. May 1978. Lit. no. 10-264T6. "State-of-the-Art Review: Pyrolysis and Combustion of PCB Substitutes," SCS Engineers, Inc..EPRI (Electric Power Research Institute) EI-4503, Project 2028-12. March 1986. Lit. no. 10-293Codes and Standards**C1. "Standard Specification for Silicone Fluid Used for Electrical Insulation," ASTM D4652-87. March1987. 545-546*C2. EEE Guide for Acceptance and Maintenance of Insulating Oil in Equipment, C57.106-1991*C3. IEEE Guide for Acceptance and Maintenance of Less-Flammable Hydrocarbon Fluid inTransformers. C57.121-1988, Table 1*C4. !EEE Guide for Acceptance of Silicone Insulating Fluid and its Maintenance in Transformers,C57.111-1989, Table I*C5. 1991 Gas and Oil Equipment Directoyi, Underwriters LaboratoriesC6. "New UJL Classification for Silicone Transformer Fluid," J. Goudie and S. Mort, ElectricalManufacturing Technologies Expo, June 1994. Lit. no. 10-579C7. "Silicone Transformers: An Update on Cunrent Product Listings, Codes and Standards," S. Mort,EPRI PCB Seminar, September 1993. Lit. no. 10-58 I* Items F7. FS. and C I-C5 can be obtained through the appropriate group or agency.1-10 Section 2: Section 2: SafetySection Content2.1 M aterial Safety Data Sheet .............................................................................................. 2-12.2 Health and Environm ental Aspects .................................................................................. 2-22.2.1 Toxicology ............................................................................................................ 2-22.2.2 Environm ental Toxicity ........................................................................................ 2-22.2.3 Environmental Entry .............................................................................................. 2-32.2.4 Environmental Fate and Effects ............................................................................. 2-32.3 Regulatory Facts .............................................................................................................. 2-42.4 Spill Inform ation ........................................................................................................... 2-52.4.1 M inor Spills ............................................................................................................ 2-52.4.2 Spills on W ater ....................................................................................................... 2-52.4.3 Spills on Roadways ................................................................................................ 2-62.4.4 Spills on Soil .......................................................................................................... 2-62.4.5 Recommended Absorbents .................................................................................... 2-62.4.6 Spill Containment ................................................................................................. 2-82.5 Fire Safety ........................................................................................................................ 2-92.5.1 Pool-Fire Burning Characteristics ......................................................................... 2-92.5.2 Extinguishment ................................................................................................... 2-112.5.3 Threat to Adjacent Buildings ..............................................................................2-112.5.4 Smoke and Combustion Products ....................................................................... 2-122.5.5 Basic Thermochemical Properties ....................................................................... 2-122.5.6 UL Fact-Finding Report ....................................................................................... 2-122.1 Material Safety Data SheetA material safety data sheet (MSDS) for Dow Corninhg 561 Silicone Transformer Liquid issupplied when the material is shipped& Many customers will have one on file in their purchasing,procurement, or receiving department.The health and safety information and recommendations reported on an MSDS can changeperiodically as new information becomes available. Therefore, the MSDS should not bephotocopied or widely distributed.If additional copies of the MSDS for Dow Corninfli' 561 Silicone Transformer Liquid areneeded, please contact Dow Corning Corporation to obtain copies of the most up-to-date versionor visit www.dowcornina.com web site.2-1 Dow Corningg 561 Silicone Transformer Liquid TechnicalManual2.2 Health and Environmental Aspects2.2.1 ToxicologyOral-The oral toxicity ofpolydimethylsiloxane (PDMS) is extremely low. No deaths haveresulted in rats at single doses as high as 30 mL/kg of body weight for 0.65-12,500 cSt viscositygrade fluids. More specifically, the 50 cSt PDMS used in Dow Corninge 561 SiliconeTransformer Liquid has been dosed as high as 50 mL/kg with no observed effects. Subacute andchronic oral studies in mice, rats, rabbits, mad dogs have uniformly failed to yield any results oftoxicologic significance. The Food and Drug Administration (FDA) permits levels of up to 10ppm of 350 cSt PDMS fluid to be added in many food-processing operations. It is also used as anantiflatulent in medical applications.Skin Response-A number of human repeated-insult patch tests have been conducted withPDMS fluids. In no case has there been an indication that the materials are skin sensitizers orskin-fatigufing agents. Dermal absorption studies have yielded no absorption in significantamoumts. Instead, the soothing and nonirritating action of PDMS fluid on the skin has resulted inthe use of many types of silicones, including PDMS fluids, in hand creams, shaving soaps,deodorants, and cosmetics.Eye Response-Instillation of PDMS into the eye causes transitory conjunctival redness thatdisappears within 24 hours. The effect is probably caused by the water-repellency of the siliconefluid that produces a feeling of dryness. This effect is a physical and not a chemical effect, whichis similar to the eye sensation that appears after long exposure to the wind. It has produced noserious health problems. Touching the eyes or facial skin close to the eyes may also result in thistemporary eye redness.When handling Dow Corning 561 Silicone Transformer Liquid, care should be taken to avoidcontacting the fluid with the eye to prevent any temporary discomfort that may result.Inhalation- Dow Corning 561 Silicone Transformer Liquid has a very low vapor pressureand thus presents essentially no inhalation hazard. Further, in inhalation studies of pyrolysis andcombustion products from Dow Corning 561 Silicone Transformer Liquid, no significanttoxicological hazards were observed when compared to normal combustion products.2.2.2 Environmental ToxicityAll studies conducted indicate a very low order of toxicity for PDMS fluids- No evidence hasbeen obtained to suggest accumulation in the flesh of fish or birds, and there appears to be nosignificant transfer of the material to the eggs of chickens. The details of the studies done areavailable in the literature or upon request.2-2 Secltion 2: Safeo42.2.3 Environmental EntrySince Dow Corning 561 Silicone Transformer Liquid is used in closed systems, theenvironmental exposure risk is relatively low even in the event of an accidental release. PDMSfluids are nonvolatile and do not evaporate to the atmosphere, thus entry points are limited to soil,surface water, landfill or a wastewater treatment plant. PDMS will preferentially adhere to soilparticles so its propensity to migrate towards groundwater is extremely limited- Thischaracteristic also simplifies clean-up since the fluid will tend to remain near the spill source.2.2.4 Environmental Fate and EffectsThe fate of PDMS is partly a function of where it enters the environment Studies have shown thatPDMS will degrade into lower molecular weight compounds, primarily Me2Si(OH)2, when incontact with soils. Testing under a variety of representative conditions has confirmed thisobservation in a wide range of different soils, indicating that the phenomenon is widespread innature.Significant degradation to lower molecular weight compounds has been noted after only a fewweeks of soil contact. The actual rate and extent of degradation vary as a function of soil moisturecontent and clay type. These lower molecular weight degradation products have been shown tofu-ther oxidize in the environment, both biologically and abiotically, to form naturally occurringsubstances: silica, carbon dioxide, and water,No effects from PDMS (or its degradation products) have been observed on seed germination,plant growth/survival, or plant biomass. In addition, research has shown no adverse effects fromPDMS on terrestrial life forms such as insects or birds, even under highly exaggerated exposureconditions.Aquatic Environments-If nonvolatile PDMS fluid should enter the aquatic environment, thematerial attaches to particulate matter and is removed from the water column by the naturalcleansing process of sedimentation. Testing on aquatic plant and animal life has revealed noecologically significant effects, even under highly exaggerated exposure conditions. PDMS fluidsdo not partition back into the water column, and they have no detectable biological oxygendemand (BOD). Bioconcentration is not a significant concern with PDMS. The size of themolecules makes them too large to pass through biological membranes in fish or other organisms.Specific testing has shown that PDMS does not bioaccumnlate in benthic organisms or variousterrestrial species, including earthworms.Wastewater-Municipal treatment plants are designed to facilitate the natural degradation ofwaste by microscopic organisms. Biomass (i.e., sludge) is generated by this degradation andeventually disposal is required. Because the water solubility of silicone fluids is essentially nil,they become a minor constituent of the sludge as they attach to suspended materials inwastewater systems. In a municipal system, treated sludge is typically incinerated, landfilled, orused as fertilizer. Wastewater treatment monitoring and simulation studies have confirmed thatPDMS fluid will be almost completely absent from the treated effluent.PDMS does not inhibit the microbial activity by which wastewater is treated. Test levels farexceeding those expected in the environment have shown no effect on the activated sludgeprocess, other than the expected benefit of foam control. The ultimate fate of nonvolatile PDMSdepends on the treatment process. If the sludge is incinerated, the silicone content converts toamorphous silica, which presents no further environmental consequence when the ash is2-3 Dow Coring 561 Silicone Transformer Liquid Technica/ Mannzllandfilled. When treated sludge is used as fertilizer, very low levels of PDMS can be introducedto the soil environment, where it is subject to soil-catalyzed degradation. Similar soil-catalyzeddegradation can also occur if sludge-botud PMDS is landfilled. Overall, there is no evidence ofany adverse effects of PDMS fluids on WWTP operations.Using the analytical test method specified by the U.S. Environmental Protection Agency, siliconefluid discharged into a wastewater sewer will be detected as an "oil and grease" type of material.However, the test method specified by the EPA also identifies other nonhydrocarbon materials as"oil and grease" materials.Most municipalities have an "oil and grease" concentration limit of 100-200 parts per million foreach customer connected to the sewer system. Minor leaks and spills of silicone fluid are unlikelyto lead to a customer's waste stream exceeding this limit. However, large spills of any material,including silicone fluid, should not be discharged to a sewer system. See Section 2.4 for moreinformation on clean up of spills. In support of their compliance responsibilities, Dow Comingcan provide suggestions to customers on how best to minimize silicone fluid losses to the sewer.2.3 Regulatory FactsThis section includes regulatory facts that can make it easier for safety and environmentalprofessionals to determine how Dow Corning 561 Silicone Transformer Liquid might beregulated according to current government law.* Dow Corning 561 Silicone Transformer Liquid is 100% trimethyl-end-blockedpolydimethylsiloxane." The Chemical Abstracts Service (CAS) number for the material is 63148-62-9.* This material is not classified as hazardous when discarded under the Resource Conservation andRecovery Act (RCRA) (40 CER 261)." The mateiial is halogen-free--there is no chlorine or bromine present.* The material contains no additives such as pour-point depressants, flow modifiers, antioxidants, orthermal stabilizers.* The material contains no hazardous ingredients as defined by Occupational Health and Safety Act(OSHA) regulations under the Hazard Communication Standard (29 CFR 1910).* The material is not listed under SARA Title III for hazardous or toxic materials.2-4 Sec/ion 2: Safely2.4 Spill Information2.4.1 Minor SpillsMinor spills on paved surfaces can be cleaned using absorbent materials. Use of a suitable solventor partial solvent will facilitate cleanup. Flammability and toxicity should be a primeconsideration in the choice of a solvent to clean up spills. Solvents should not be used on asphaltsurfaces since they will dissolve the asphalt.Table 2-1. Solvents and partial solvents for silicone fluidsSolvents Partial SolventsAmy[ acetate AcetoneCyclohexane ButanolEthylene dichloride Oloxane2-Ethyl hexanol EthanolHexyl ether HeptadecanolMineral spirits isopropanolNaptha VM&PStoddard solventTolueneTurpentineXyleneGasolineKeroseneMethylethyl ketone (MEK)Methylisobutyl ketone (MIBK)2.4.2 Spills on WaterSection 311 of the Federal Clean Water Act imposes strict reporting requirements when certainsubstances are spilled onto navigable waters.The requirement to report is not triggered by a specified quantity of spilled material, rather it istriggered by the discharge of an amount of material that causes a sheen on the water. Thus, ifPDMS fluids are spilled in large quantities on navigable waters and produce a visible sheen, theU.S. Coast Gnard must be notified immediately at 1-800-424-8802.Since silicone fluids are nearly insoluble in water and are lighter than water, they will remain atthe surface of the water and can be removed using hydrophobic materials such as polypropylenemats, pads, or booms. The polypropylene material will soak up the silicone fluid while repellingthe water. Once the absorbent material becomes saturated with fluid, it can be discarded as anonhazardous solid waste or regenerated by squeezing the pad, mat, or boom to release the fluidfor disposal or recovery. For more information on recovery of silicone fluids, see Section 6.5:Recycling and Disposal of Silicone Transformer Fluid.A silicone/water mixture can also be passed through a filter containing treated cellulose such asABSORBENT W', which can selectively absorb the silicone fluid while allowing the water to passthrough. Table 2-2 is a list of recommended absorbent materials and filter media for heatingABSORBarT W is a tadcmark ofMinnesota Absorption Corporation.2-5 Dow Corning 561 Silicone Transformer Liquid TechnicalManualsilicone fluid that has been spilled into water.2.4.3 Spills on RoadwaysThe chief concern in a roadway spill is the loss of tire traction caused by the lubricating action ofthe silicone fluid. On concrete or asphalt, silicone fluids have about the same degree of lubricityas motor oil.Spills of silicone fluid on paved surfaces should be cleaned up as quickly as possible to avoidunnecessary spread of the material or potential contact with water or precipitation that could thenrequire addition cleanup action. Spilled silicone fluid can be absorbed with materials that arecommonly used to soak up oils and solvents. These include plastic fibers and pads, cellulose-based fibers and granules, and expanded clay solids. In an emergency, dry sand can be used, but itis less absorbent than the other types of materials.The choice of absorbent may be dictated by the final disposal option. For example, the siliconefluid/absorbent mixture may be landfilled as nonhazardous solid waste, provided there is no freeliquid in the absorbent mixture. If the landfill operator prefers a nonbiodegradeable absorbent forburial, the plastic fiber or expanded clay would be a better choice than biodegradable cellulose. Ifincineration was selected as the final disposal option, the cellulose product would be preferredsince it would be fully combusted and would not contribute to ash residue.For a silicone fluid spill on a paved surface, absorption of the fluid followed by thoroughsweeping of the surface with clean absorbent should be adequate to prevent fluid runoff if thesurface is subsequently wetted with water. Solvent cleaning of roadway surfaces is usuallyunnecessary. Residual silicone will attach to the paving material and act as a water-repellentagent.The time required to remove Dow Corning 561 Silicone Transformer Liquid depends on thephysical absorbent and the amount of fluid present. Periodic replenishment with fresh absorbentsspeeds up the removaL2.4.4 Spills on SoilA minor spill of Dow Corning 561 Silicone Transformer Liquid on soil can be cleaned up byremoval of the soil until there is no visual discoloration of the remaining soil. In most states, thecollected discolored soil can be legally landfilled as a solid nonhazardous waste.Should such a cleanup operation be necessary, Dow Corning recommends that the appropriatestate and local government officials be contacted before landfilling any material.2.4.5 Recommended AbsorbentsDow Corning performed a laboratory evaluation to assess the efficiency of nine commerciallyavailable absorbents for Doie Corning 561 Silicone Transformer Liquid. Absorbency wasmeasured for both the silicone fluid and for a water/silicone mixture.The best results were observed using polypropylene pad materials. Polypropylene is ahydrophobic material that repels water while attracting nonpolar fluids and oils. For absorbingspilled fluid on a dry surface, a stitched polypropylene pad soaked up 12 times its original weight,while a pillow configuration absorbed 13 times its weight. Both products can be reused by2-6 Section 2: Safet,squeezing them to release most of the trapped fluid. When silicone fluid was poured onto a watersurface, the polypropylene pillow and the stitched pad again performed the best.Products that absorbed the least amount of fluid included ground corn cobs (SLICKWIK),untreated cellulose (ABsoRBENT GP), and cotton fiber (Conwed Sorbent Rug). These results aresummarized in Tables 2-2 and 2-3. Expanded clay and vermiculite (kitty litter) products were nottested since loose products are not practical for absorbing and recovering silicone fluids on watersurfaces-The better performing absorbents were able to selectively remove 90-95% of the fluid from thesurface of the water. To remove any remaining visible sheen, best results were achieved bypassing the mixture through a filter packed with treated cellulose fiber (ABSORBENT W). Thissecond filtration/absorption step reduced the silicone content in the water to below 10 ppm.Table 2-2. Relative performance of absorbents with Dow Corningo 561 in waterRank Type Product Name Supplier Contact1 Polypropylene pillow PIL 203 J New Pig Corporation 800-468-46472 Polypropylene stitched mat MAT212 J New Pig Corporation 800-468-46473 Polypropylene mat pad MAT21 5 J New Pig Corporation 800-468-46474 Polypropylene quilted pad MAT403 J New PIg Corporation 800-468-46475 Ground corn cobs SLICKWIK Andersons Company6 Polypropylene plain pad HazwIck7 Treated cellulose Minnesota Absorption Corp. 612-642-92608 Blue cotton fiber roll Conwed 76700 Sorbent Rug Sansel Supply Company 216-241-03339 Untreated cellulose ABSORBENT GP0Minnesota Absorption Corp. 612-642-9260Table 2-3. Relative performance of absorbents with Dow Corning 561 on drysurfaceIRank123456789TypePolypropylene pillowPolypropylene stitched matPolypropylene mat padPolypropylene quilted padPolypropylene plain padBlue cotton fiber rollGround corn cobsTreated celluloseUntreated cellulosePerformance13x`12x`lox7x`5x4x`3x2xL-.ý2-7 Dow Cornlngt 561 Silicone Transformer Liquid Technical Manual2.4.6 Spill ContainmentFederal, state, and local regulations can impose different requirements that should be reviewed. Inaddition, good manufacturing practices (GMP) and product stewardship policy will dictate someform of spill containment for materials that have risk factors that warrant such protection.Examples of risk exposure consideration include:* Proximity to waterways" Potential for fire and fire water runoff" Potential for spillage firom material transfer activitiesBecause silicone fluids are neutral and lighter than water, spill containment, when deemedprudent, can consist of an "over and under" baffled sump similar to a small household septic tank.This configuration will trap and retain the fluid while allowing water to pass through for routinedisposal.2-8 Section 2: Saftly2.5 Fire SafetyThe excellent reliability, performance, and economics of conventional fluid-filled transformershave been well established by end-users. They have a strong interest in transformer liquids thatcan replace askarels as well as meet present and future safety requirements.The concept of the fire hazard of systems is replacing the narrower concept of flammability ofmaterials. The most valid fire-hazard tests are those that evaluate the entire system underconditions that closely simulate use under realistic worst-case scenarios. The followingcharacteristics are related to the fire hazard to buildings and people:" Heat release" Smoke and fire gases* Fire growth/flame spread" Arc gases* Oxygen depletion" Ease of ignition" ExtinguishmentMost of the current fire-hazard data for transfonner fluids has been generated by conductinglarge-scale pool-fire tests.2.5.1 Pool-Fire Burning CharacteristicsThe effect of the diameter of the burning pool of fluid on the combustion rate (rate of heatrelease) has been studied extensively for hydrocarbon fires over a wide range of pool diameters.The flame height in a hydrocarbon fire has been shown to be 2.5 times the diameter of the poolfor pans 4 feet in diameter and larger- The combustion rate of silicones decreases with increasingpan size. The flame height stabilizes at I to 2 feet at a pan size of approximately 4 feet.Silicone transformer fluid will reach a maximum sustained rate of heat release (RIR) afterignition. This peak value is maintained for several minutes. The RHR then decreases with time.This is in contrast to hydrocarbons that typically reach a steady-state RHR that is maintained untilthe material is consumed. It is the peak RHR that is reported and used to assess potential hazard.The silicone peak value is 10 to 18 times lower than the average value for hydrocarbons. Figures2-1 and 2-2 from pan-bum studies show the characteristically different bum behavior of silicones.The fire hazard to buildings, structures, and equipment can be assessed by the heat released. Therate of heat release is therefore important- Insurance companies in the U.S. use the RHR value toclassify materials used in transformers.By adding external heat to a pool fire, the behavior of the fluid toward an external fire can bestudied. Figure 2-3 shows that the convective RHR will increase as the external heat flux isincreased for two high-fire-point hydrocarbon transformer fluids. The RHR forsilicone fluid shows little increase with increasing external heat flux. The data suggest that ahigh-fire-point hydrocarbon could dramatically fuiel a fire, but a silicone fluid would make littleor no contribution.2-9 Dow Corning 561 Silicone Transformer Liquid TechnicalManual4000S=C=IxIIx31001*5G L r~nmrtUC=a:200011000f,0 10 20Time (minutes)30 4040Time (minutes)Figure 2-1. Rate of heat release for transfonnerfluds it 12-inch diameter pan-burn test40Cr20a:10U0SII0 ...Figure 2-2. Rate oIheat release for DowCorning 561 hn 24-inch diam eter pan-burn testM0E~0 1 2 3 4Extemal heat flux (watts/cmg)5 610-4 10-2 100 102 10'Characteristic pool dimensions (cm)Figure 2-4. Burning rate per unit area as afinction ofpool (or droplet) diameterFigure 2-3. Convective rates of heat release fortransfonner fluids in 4-foot diametertestThe normalized value of RHR (RHRIarea) hasbeen used to predict the RHR of larger pansizes. Figure 2-4 shows the relationshipbetween burning rate and pool size forhydrocarbon bums. The RHR/mi will typicallylevel off at a 4-foot diameter pan forhydrocarbons.For hydrocarbons, the normalized heat releaserate shows a dramatic increase as pan sizeincreases (see Figure 2-5). The change in thenormalized heat release rate as silicone burnsize increases, in the same figure, is much lessdramatic. The data in Table 2-4 were generatedfor hig -fire-point hydrocarbons and DowCorningg 561 Silicone Transformer Liquid..5-a:160012008004000IE3130--I10100Pool diameter (inches)Figure 2-5. Peak rate of heat release fortransfobnner fluids2-10 Section 2: SafetyTable 2-4. Summary of normalized RHR data (all data in kW/m2)Dow Corning FMR Independent Test LabPoly-uc-olefin (PAO) 1430 1020 1240High-FP hydrocarbon 1200 1050 1270561 Transformer fluid 65 104 109The decrease in the RHR/area with increased pan size and the decreasing RHR with time in apool fire result firom the progressive formation of a crust of ash and silica that forms over thesurface during a pool fire involving the silicone transformer fluid. The ash consists of acontinuous pattern of white silica "domes" approximately 1 cm in diameter. A brown or black gellayer is formed beneath the domes. Energy feedback from the flame is inhibited sufficiently toresult in self-extinguishment, leaving a pool of clear, colorless, uiaburned fluid beneath the ashand gel.2.5.2 ExtinguishmentExtinguishing a fire involving Dow Corning 561 Silicone Transformer Liquid can best beaccomplished using high-expansion foam, protein-based foam, or carbon dioxide or dry chemicalextinguishers.Industrial sprinkler systems are also effective. Tests using an indoor calibrated sprinkler systemshow that silicone fluid fires are extinguished in 20 to 30 seconds with 0.15 gpm/ft2 of water. Asis common practice, high-velocity water streams should never be used to extinguish an electricalor chemical fire.2.5.3 Threat to Adjacent BuildingsFires associated with transformers located outdoors can pose a severe threat to adjacent buildings.Several NFPA and IEEE standards, as well as Factory Mutual Engineering and Research LossPrevention Data Sheet 5-4 on transformers, recommend minimum distances between transformersand adjacent buildings. Despite the availability of this information, applying the data to actualtransformer installations is not well understood.Recently, Dow Coming commissioned a study by Factory Mutual Research Corporation todetermine safe distances between fluid-insulated power distribution transformers located outdoorsand adjacent buildings- This "safe distance" would prevent a transformer fire firom spreading toan adjacent building or structure. The study was performed for transformers with ratings up to5000 kVA.The general approach to the problem included:" An examination of loss experience regarding transformer fires reported to Factory Mutual" A theoretical analysis of fire conditionsThis approach was followed for several types of transformer fluids-including mineral oil, highmolecular weight hydrocarbons (HMWH), and silicone-and for common types of building con-struction-wooden walls, asphalt roofs, steel on steel framne (noncombustible) walls, and one-hour- or two-hour-rated walls. In the report, the results are presented in the form of graphs, tables,and/or equations.2-11 Dow Corningi) 561 Silicone Transformer Liquid TechnicalManualIt was found that for a typical fluid-insulated distribution transformer fire, the safe separationdistance from a wooden structure is 14.8 m (49 ft) for the case of mineral oil fluid, 12 in (39 ft)for HMWH fluid, and 2.5 in (8 ft) for silicone fluid. Similar trends were reported for otherbuilding materials.For more information on this study, contact Dow Corning Technical Service and Development oryour local Dow Coming representative.2.5.4 Smoke and Combustion ProductsSmoke from silicone transformer fluid fires is typically 3 to 5 times less dense than high-fire-point hydrocarbon smoke. The smoke consists of tan-grey particulates that are almost entirelyamorphous silica. The 0,-depletion rate for testing at the same smoke density has been measuredat 600 liters/minute. Animal studies have indicated that the combustion products of siliconetransformer fluid have little or no potential to cause serious injury, especially as compared to theaffects of the combustion products of mineral oil or askarel.2.5.5 Basic Thermochemical PropertiesTable 2-5 is a summary of the thermal stability properties and burning properties of DowCorning 561 Silicone Transformer Liquid.Table 2-5. Summary of thermal stability and burning properties of Dow Coming 561Property ValueViscosity 50 cstFlash point 6720F (300'C) minimumFire point >600TF (350*C)AutoIgnition temperature 435"CVolatility 0,5%Thermal conductivity 0.00036 cal/sec-cm.°C @ 5O'CLimiting oxygen index 18.5--19% 02Heat of combustion 6.7 kcal/gRate of heat release 100-120 kcalm2 (4-ft pan)2.5.6 UL Fact-Finding ReportThe UL Fact-Finding Report for less flammable transformer fluids is available fromDow Coining.2-12 Section 3: Transformer Design hIformationSection 3: Transformer Design InformationSection Content3.1 Dielectric Data ................................................................................................................. 3-13.1.1 Dissipation Factor, Df ............................................................................................ 3-13.1.2 Dielectric Constant, DK ......................................................................................... 3-33.1.3 Electrical Breakdown ............................................................................................. 3-33.2 Thermal Capabilities ........................................................................................................ 3-63.3 Pressure Increases ............................................................................................................ 3-83.4 Partial Discharge Characteristics ..................................................................................... 3-93.5 Load-Break Switching Performance .............................................................................. 3-103.6 M edium and Large Power Transformer Applications ................................................... 3-113.7 M aterial Compatibility ................................................................................................... 3-123.8 Physical Characteristics ................................................................................................. 3-143.8.1 Vapor Pressure.............. .............................................. 3-143.8.2 Volume Expansion ............................................................................................... 3-143.8.3 Solubility of Gases ............................................................................................... 3-163.8.4 Viscosity-Temperature Relationship ................................................................... 3-173.8.5 Specific Heat ........................................................................................................ 3-183.8.6 Density ................................................................................................................ 3-183.9 Lubricity ......................................................................................................................... 3-193.10 Refrofill Considerations ................................................................................................. 3-213.10.1 M aterial and Component Compatibility .............................................................. 3-213,10.2 Temperature Rise/Heat Transfer .......................................................................... 3-213.10.3 Fire Safety Considerations ................................................................................... 3-243.1 Dielectric DataThis section presents and discusses a variety of typical dielectric properties that are important tothe performance of transformer fluids.3.1.1 Dissipation Factor; DfDow Corning 561 Silicone Transformer Liquid is a low-loss, nonpolar material as measured bydissipation factor or power factor. Dissipation and power factors are related by the followingequations:If 0 is the phase angle and 8 is the loss angle,a+8= 90,Power factor = cosODissipation factor = tan83-1 Dow Cornmng* 561 Silicone Transformer Liquid TecinicalManualFor Dow Corning 561 Silicone Transformer Liquid, typical values of the dissipation factor areapproximately equal to the power factor. Figures 3-1 through 3-3 show the dissipation factorversus temperature, fretqency, and voltage stress. Figures 3-4 and 3-5 compare the dissipationfactor of silicone with mineral oil using two conmmonly used transformer insulation types.1.00X'C0.9.0.10aC'-0 0.100C0.010C-D0.01 A-25 0 25 50 75 100 125Temperature, 0C150Figure 3-1. Typical dissipation factor abiesversuts temperatureFrequency, hertzFigure 3-2. Frequency response of dissipationfactor1.00X'_.10.9.OAPm qaay 60 bar&8oth3"C1[ alt8abttahts1.0000o0.1000CDo 0.01005, 0,00100.00010 20 40 60 60 100 1200 50 100 150Temperature, C200 250Voltage stress, volts/milFigure 3-3. Dissipation factor versus voltagestressFigure 3-4. Dissipation factor ofkraft paperinmpregnated irith transformer fluddsC-.Co0.0 03.00z75m 2.50, 22.250xl-'0- srm=,wtidS I I-qaty U H0.00012.00'-500 50 100 150 200Temperature, 'C2500 50 100Temperature, *C150 200Figure 3-5. Dissipation factor of NOME" 410impregnated with transfonnerfluddsFigure 3-6. Typical valies of dielectric constantversus temperature*-NON= is a restered tzademak ofEL Du Pont dE Nemaurs Company. Inc.3-2 Section 3: Transformer Design Information3.1.2 Dielecric Constant, DKDielectric constant (sometimes referred to as permittivity, capacitivity, or specific inductivecapacity) is the ratio of the capacitance of the material in a particular test configuration to thecapacitance of the same configuration in air. Figures 3-6 through 3-8 show the dielectric constantof Dow Corning 561 Silicone Transformer Liquid as a function of temperature, frequency, andvoltage stress.2Q.5S2.73 ,,Teonperture: 23*CCell., BaIzbhugb 100T3Bridge Geer MRadio 7162.722.712.70 , ...L I L .L..U.Uh ....L.LL!fl101 U0P 103 10, 10' 10'Z.52.732.72 2Temperatur: 2-rC [[requency:60 ItICe eaflazbiubh 3HT35 U[i j: Beckan loL .2.712.700 20 40 60 80 100 120Frequency, hertzFigure 3- 7. Frequency response of the dielectricconstantVoltage stress. volts/milFigure 3-8. Dielectric constant versus voltagestress3.1.3 Electrical BreakdownThe dielectric breakdown of silicone fluid according to D877 is discussed in Section 6.1, PeriodicInspection and Testing. The effect of water contamination on the results of this test is discussed inSection 6.2, Contamination. The current section deals with the impulse breakdown strength ofDow Corning 561 Silicone Transformer Liquid and its breakdown strength in combination withpaper insulation. Since the nature of this testing is such that comparisons are the most valuable,Figures 3-9 and 3-10 include data for other transformer fluids. Figure 3-11 reports the uniformfield breakdown of silicone fluid at various levels of water content for two different ASTM tests.EEMCLE1icone Sicona + Mnora OR Ad"126 p9m waorTransformer lquidFigure 3-9. Sphere-to sphere impulsebreakdouw Inlef elsfor transformerfluidsslkcae sficane+ S~iaie+ Mnero] 01 Askarellalppmwater 20!TCRTransformer liquidFigure 3-10. Impulse breakrdown of 1xOiD mfluid-impr-egnated paper (sphere-to-sphere electrodes)3-3 Dow Corning 561 Silicone Transfor-mer Liquid Techrnical ManvalThe electrical-breakdown data presented in Tables3-1 thr'ough 3-4 and Figures 3-12 and 3-13 provide _Egeneral information as to the relative performance >of silicone in specific test configurations.Table 3-1. Breakdown of 10-mil aramid paper/fluid composite insulation (sphere-to-ball electrodes at 250C)1UU I-AI--- bpneA tkdnAS-~ ~ ~ ~~0 A........ ......................Silicone Mineraloil60 Hz, 3 kyisecond rate of riseBreakdown voltage, Vlmll 1923 1966Standard deviation, V/mll 124 233Number of tests 12 2060 Hz, 1 ky/minute step riseWithstand voltage, Vlmil 1200 1205Standard deviation 146 94Number of tests 18 181.2 x 50ips positive ImpulseWithstand voltage, V/mll 3159 3054Standard deviation. V/mll 146 126Number of tests 18 16Table 3-2. Breakdown of 10-mul kraft paper/fluidcomposite insulation (sphere-to-planeelectrodes at 250C)Silicone Mineraloil60 Hz, 3 kVIsecond rate of riseBreakdown voltage, V/mll 1570 1894Standard deviation, V/mll 94 195Number of tests 75 2060 Hz, I kVlminute step rise1-min withstand voltage. Vlmll 1211 1183Standard deviation, V/mll 78 72Number oa tests 10 12ag0 L_ , I I0 50 100 150 200 250Water content, ppmFigure 3-11. hIpact of water content on unnfonnfield breakdown for silicone fluidI;E4.03.53.02.52.01.51.00.5..........10 20 30 40 50 60Gap length, mmFigure 3-12. Influence of gap length on srufaceflashover impulse voltage-positiveimpulse4;aIaCoI60Gap length, mmFigure 3-13. Influence of gap length onsmifaceflashover impulse voltage-negative pulse3-4 Section 3: Transformer Design InformationTable 3-3. Repeat breakdown--initial penetration from 40 kV impulse discharge;repeat strength at 60 Hz, 250C and 3 kV/s rate of riseSilicons Mineral oil AskarelBreakdown, mean. V/mll 942 277 0Number of tests 18 20 19Number of O's observed 3 10 19Table 3.4. Breakdown strength versus humidity and water exposure-80 Hz, 250C,and 3 kV/s rate of rise7 days @ 85% 60 days withExposure After vacuum RH water interface1 0-mll kraft paper/silicone fluid composite insulationBreakdown voltage, mean, V/mul 1559 1442 1584Standard deviation. V/mul 104 149 43Number of tests 24 24 2010-mi) kraft paperlmineral oil composite InsulationBreakdown voltage, mean. Viml] 1899 1735 1745Standard deviation, Vlmul 216 238 127Number of tests a 8 14Results from a recent study using low-density kraft board and low-density Nomix boardindicated that Dow Corning 561 Silicone Transformer Liquid and mineral oil perform similarlywhen subjected to negative and positive lightning impulses and 60 Hz ac power. Electricalbreakdowns under positive impulse voltages are generally lower than those under negativeimpulse voltages. Permittivity matching appears to be a factor in the dielectric strength of theinterface to impulse voltages. For ac voltages, poor resistance to partial discharges may overridethis effect. Figures 3-14 and 3-15 show the average breakdown voltages on low- and high-densitykiaft and NOMEX pressboard.300 300S250 2502o 2o(D)200 2001o 0ot~3: 150 ý0 150o I0100 aC ac ac ac 2100 BC acInlestcigIestTy mDity50 5. pondtl:s .par. WaNm50w .nr.3e poov.4 .4.0b awe- 's twd00Low Density High Density Low DensityFigure 3-14. Mean breakdoitw voltages on both high- andlow-density kraft paper board (Bars with a + symbolrepresent breakdown roltages with positive impulsevoltages; bars withs a -symbol represent negativeimpulses; and bars with "ac' represent altemwadngczin'nt impulses.Figure 3-15. Mean? breakdown1'oltages on lowr-densityNomEx paper board3-5 Dow Corningg 561 Silicone Thunsformer Liquid Tec/mica!Manual3.2 Thermal CapabilitiesSilicone transformer fluid differs from mineral oil and askarel in that, aside from a controlledmolecular-weight distribution, it is chemically homogeneous and not a mixture containing somerelatively volatile constituents. It is more heat stable than the other two fluids. Thesecharacteristics allow silicone transformer fluid to be subjected to very high temperatures-wellabove normal transformer operating temperatures-without creating excessive vapor pressure orcorrosive by-products. Silicones are chemically inert, have good oxidation resistance, and arecompatible with conventional insulating materials at transformer operating temperatures.Table 3-5 summarizes the results of a test conducted to demonstrate the dramatic difference inthermal stability between silicone fluid and conventional transformer fluid. Open test tubescontaining the two fluids were aged in a heat bath for 500 hours at 1600C. The aging caused grossvolatilization and oxidation of the mineral oil; all that remained at the end of the test was a darksludge. In contrast, no change was observed in the silicone fluid; there was no evidence ofvolatilization or oxidation. Although no transformer fluid is intended to be subjected to thesetemperatures, the data illustrate the enhanced behavior of the silicone fluid.Table 3-5. Thermal stability of silicone and mineral oil transformer fluids (open tube, 160°C)Mineral oll Silicone transformer fluidAging time Initial 24 h 100 h 500 h Initial 100 h 500 hPhysical propertiesAppearance Pale Medium Dark Black Clear, Clear, Clear,yellow brown brown colorless colorless colorlessWeight loss, % -14.4 33.7 75.1 -0.053 0.141Viscosity, cSt @ 23*C 17.8 19.0 24.5 62.0 49.0 49.5 49.0Dielectric propertiesDielectric constant, 100 Hz 23*C 2.26 2.27 2.29 2.46 2.72 2.72 2.72Dissipation factor. 100 Hz 23°C 0.0014 0.00075 0.0039 0.0072 0.000018 0-000i1 0.000053Volume resistivity. ohm-cm. 234C 8.4x1012 8.7x10(12 2.4k1012 9.5K1012 7.1 x1014 1.1x1014 5.9x 101The pronounced difference in stability between these two types of fluids can be understood byexamining what takes place in these fluids at high temperatures. Mineral oil begins to volatilizeand oxidize rapidly at temperatures above 105'C. Oxidation results in the formation of manyobjectionable degradation products. These products, which include organic acids and sludge,cause problems in a transformer by reducing the dielectric properties of the insulation and bycorroding metals.There are two modes of degradation for silicone fluid: thermal breakdown and oxidation. Thermalbreakdown of silicone fluid begins at temperatures above 230*C (4500F). At these temperaturesthe longer polymer chains will slowly begin to degrade to form more volatile cyclic siliconematerial.Oxidation of silicone fluid will take place very slowly (in the presence of oxygen) at temperaturesabove 1750C (3421F). When it oxidizes, silicone fluid polymerizes, gradually increasing inviscosity until gelation occurs. This process takes place without the formation of objectionableacids or sludges. In addition, the dielectric properties of the longer-chain silicone molecules aresimilar to the dielectric properties of fresh silicone fluid.3-6 Section 3: Transformer Design InformationThe temperatures at which thermal and oxidative degradation take place are well in excess of thehot-spot temperatures expected in 65°C-rise transformers. In the limited-oxygen atmosphere ofsealed transformers, silicone transformer fluid can be used at temperature rises that are abovestandard rises of other transformer fluids.The silicone transformer fluid is not expected to degrade in any significant manner over theuseful service life of a 65°C-rise transformer.Insulation systems using silicone fluid in combination with solid insulating materials havinghigh-temperature capabilities have shown significantly improved thermal capabilities and longerinsulation life. Several studies have been reported regarding such a system. Work conducted byboth Westinghouse and Dow Coming examined the thermal capability and long-termperformance and reliability of high-temperature capability model transformers. Researchers atWestinghouse constructed such a transformer using a 25 kVA type S-CSP 7200 240/120VWestinghouse distribution transformer.The insulation system consisted of silicone fluid in combination with baked aromatic polyesteramide/imide (OvmeAt), NoIEX paper, and glass materials. The unmit was loaded electrically forlife-test aging, with the loading adjusted to maintain a hot-spot temperature of 225 0C, asmonitored by a thermocouple in the hot-spot area of the high-voltage coil. The top liquidtemperature was approximately 145°C.The researchers reported that after 10,000 hours of operation at a hot-spot temperature of 220'C,the unit was in excellent condition. Based on IEEE Standard 345-1972, this would correspond toover 200 times the life expectancy (in hours) of a 650C-rise distribution transformer operating at2200C. The silicone fluid was still a clear water white in color. The results of fluidcharacterization tests performed during the aging study are shown in Table 3-6.Table 3-6. Properties of 50 cSt PDMS fluid in life-test transformer at 2200C hot-spot temperatureOriginal After 1650 h After 9000 h After 10000 hGeneral condition Clear Clear Clear ClearDielectric strength, kV 35 28 33 28Power factor, % @ 60 Hz. 25°C 0.007 0.01 0.004 0.006Interfacial tension, dynes/cm 44.6 40.9 33.7 32.9Neutralization number, mg KOH/g 0.002 0.03 0.05 0.02A similar study performed by Dow Coming showed comparable results. In this study, two 25kVA distribution transformers with high-temperature insulation systems were aged 10,000 hoursat a hot-spot temperature of 200°C. Top liquid temperatures were approximately 1050C. After10,000 hours of aging, the flash and fire points of the silicone fluid were 324°C and 343°C,respectively, unchanged from typical values for new fluid.Thermal analysis data have also indicated that 50 cSt PDMS fluid is considerably more thermallystable than mineral oil. Sealed-tube thermal-aging studies of kiaft paper and FoRIuVARt -basedenameled wire in 50 cSt PDMS fluid indicated that the usefil life of both materials is similarwhether aged in silicone fluid or mineral oil. However, the silicone fluid was relativelyunaffected by either the degradation of the solid insulation materials or the thermal exposure.%OiEGA is a Iegisteied n-ademark of'WcsnjhoiseFORMVAR is a uademadk ofrMonsanto Chemical Company3-7 Dow ComlnWg 561 Silicone Transformer Liquid Technical Manual3.3 Pressure IncreasesWhen temperature increases, Dow Corning 561 Silicone Transformer Liquid expands morethan mineral oil or askarel. Classical gas-compression/pressure equations predict that thisincrease will create higher pressures in silicone-filled transformers than those observed inaskarel-filled units. Relief valves, lower fluid levels, and tank redesign have been considered-However, in pressure versus temperature experiments comparing, mineral-oil-filled, askarel-filled,and silicone-filled transformers, transformer manufacturers have found that there is actually verylittle difference in the final pressure developed and that the pressure developed is significantlyless than predicted values.In the laboratory, Dow Coming conducted pressure versus temperature experiments in a sealedpressure bomb and collected the data shown in Table 3-7.These data were collected in a steel pressure bomb with an air-to-silicone fluid ratio of 0.176.When the bombs were first heated to 1000C, the pressure of the silicone-filled bomb rose to 7.25psi, but equilibrated at 4.8 psi. The pressure of the askarel-filled bomb rose to 7.3 psi andequilibrated at 4.2 psi. Both fluids took about 23 hours to equilibrate. Although rate data werelimited, it appeared that the silicone equilibrated a little faster. The pressure reduction followingequilibration is probably a result of gas absorption.These data indicate that neither the silicone nor the askarel generate the high pressures predicted.They also show that the pressure resulting from the use of silicone fluid is not sufficiently greaterthan the askarel liquid to be of concern in transformers.Refer to Section 3.8, Physical Characteristics, for information on voliume expansion and gassolubility.Table 3-7. Pressure in sealed bombs containing transformer fluidsSilicone AskarelInitial pressure after filing and sealing at 230C 0.0 psig 0.0 pslgEquilibrium pressure at 100"C 4.8 psig 4.2 psigCalculated pressure at 100'C 23.2 psig 10.3 pslgEquilibrium pressure at 0*C --3.6 psig -4.2 pslg3-8 Section 3: Transformer Design nformation3.4 Partial Discharge CharacteristicsAccording to one study, the partial discharge inceptive field strength (PDIF) of clean siliconetransformer fluid is similar to that of mineral oil presently used in transformers.' If the siliconetransformer fluid is contaminated with water, the PDIF decreases linearly with increasing watercontent. That relationship is shown in Figure 3-16.Measurement of pulse amplitudes and rates atdischarge conditions show that although theinception phenomenon is very similar in bothsilicone transformer fluid and mineral oil, thedevelopment and growth of the partial dischargesare quite different. The chemical and physicalproperties of the silicone transformer fluidsuppress the large discharge pulses observed inmineral oil at higher voltage stresses.EEF3(L40UJ350320250Gelled polymer substances are formed by long- 0 sotime high-level partial discharges in the silicone Water ctransformer fluid. The quantity of gelled material is Figure 3-16. Changesdependent on the total amount of the partial with water content Dodischarge energy dissipated in fluid. The gelconsists of cross-linked polymer structures of Si-CH2-Si, Si-OH, and Si-H.100:ontent, ppm150 200in mode value of PDIFw CorningO 561The investigation indicated that in the design of high-voltage equipment with silicone transformerfluids, it is important to keep stress levels below the critical corona conditions that are necessaryfor the formation of the polymerized substances-Studies conducted by Dow Corning have produced the partial discharge data listed in Tables 3-8and 3-9.Table 3-8. Discharge characteristics as determined by needle-plane screening testDIV, kV DEV, kVDow Corning 561 16A 15.2Mineral oil (10 cSt) 19.3 17.0Askarel 20 20Table 3-9. Discharge characteristics of impregnated 0.01 gF capacitors (two layers of 0.5-milpolypropylene film)DIV, volts DEV, voltsDow Coming0 561 2600 600Mneral oil (10 cSt) 2200 600Askarel 2300 1700Kuwaham, H.: Tsimmta, I.; Mumenma. H.; Ishii. T.; and Sbimoi, H.; "Partial Discharge Characteristics of Silicone Liquids," IMEE 1975 WinterPower Meeting, Paper No- 3,75.236-5.3-9 Dow Corningg 561 Silicone Tramformner Liquid TechnicalManual3.5 Load-Break Switching PerformanceDisconnect switches and fuses are commonly applied in pad-mounted transformers. The LBORIIthree-phase rotary disconnect switch from ABB Transformer Components Division is a typicalchoice. To satisfy the demand for a fire-safe fluid in those units, an evaluation of this switch'sperformance in a 50-cSt dielectric-grade silicone fluid was undertaken.The load-switching tests were performed in accordance with ANSI 037.71, "Three-Phase,Manually-Operated Sub Surface Load Interrupting Switches for AC Systems" at the PSM HighPower Laboratories in East Pittsburgh, PA. Extensive material analyses were completed in DowCorning's laboratories and in the ABB Materials Labs formerly located in Sharon, PA.The key findings of this study were:" All structural and gasket materials were found to be compatible with the silicone fluid from roomtemperature up to 1250C. These tests were performed in accordance with ASTM D-3455,"Standard Tech Methods for Compatibility of Construction with Electrical Insulating Oil ofPetroleum Origin."* No mechanical problems or visual signs of excessive wear were observed in the switch after over11,000 operations in the silicone fluid." The switch and silicone fluid performed well in over 120 load-switching operations, including fidlyinductive load switching and currents of up to 300 A at 15 kV.* The dielectric strength of the fluid remained above the IEEE-recommended values for continuoususe in transformers throughout the tests.* All physical properties, including the flash and fire points of the fluid, were maintained throughoutthe tests. No discoloration of the fluid was noted, even after exposure to temperatures up to 1251Cfor as long as 164 hours." There was no evidence of gelling of the silicone fluid.The reports detailing this performance are available from Dow Corning and are listed in Section1.5, Bibliographic Resources, as items P7 and P8.3-10 Secflon 3: Transformer rDesign Information3.6 Medium and Large Power Transformer ApplicationsDow Corning 561 Silicone Transformer Liquid has over 20 years of proven performance insmall power transformers. These transformers have primary voltages of 69 kVA or less.However, the thermal stability and environmental and fire-safe characteristics of silicone fluidhave resulted in growing interest for certain mediun and large power transformer applications.Mobile transformers, for example, must deliver maximnmn MVA output with a mininnun of size,weight, and environmental hazard for transportation over public roadways.Medium and large power transformer applications can differ in several respects firom thetraditional applications of silicone fluid in small power transformers. Among these differences arehigher primary voltage rating and basic impulse levels (BEL), pumped fluid cooling rather thanconvective flow, use of load-tap changers in the fluid and, of course, a higher power-handlingcapability within the unit. Care must be taken to evaluate the pertinent dielectric, lubricity, andheat-transfer properties of silicone to achieve a proper design of the unit and its components.Lubricity requirements and effects of low-current arcing from on-line load-tap changes can drivedesign requirements for load-tap changers immersed in silicone fluid. Lubricity is discussed inSection 3.9.Resistance to partial discharges and partial discharge inception and extinction field strengths, aswell as surface creepage strength, can drive dielectric stress design requirements. Dielectric datafor silicone fluid and comparisons with mineral oil are provided in Section 3.1. Additional dataon dielectric properties of silicone fluids can be obtained by requesting copies of the technicalpapers listed in Section 1.5, Bibliographic Resources, under the subheading "High VoltageStrength" or by contacting the appropriate Dow Corning technical service department.Fluid compatibility with cooling pump design and other materials of construction is also animportant consideration. Types of pumps that have proven to be suitable are discussed in Section5.4, and material compatibilities are covered in Section 3.7. Heat-transfer properties of siliconefluids are discussed and compared with mineral oil in Section 3.10.2.3-11 Dew Corningt, 561 Silicone Transforner Liquid TechnicalMarnal3.7 Material CompatibilityCompatibility and thermal stability are closely related. Materials that are compatible at roomtemperature may become incompatible at elevated temperatures because of increased solventaction or chemical activity at the higher temperatures. Also, when thermal degradation of onematerial begins, the products of degradation may attack other materials in the insulation system.Regardless of the initial cause of degradation, the result of this type of incompatibility can befailure of the entire insulation system.Silicone transformer fluid has acceptable compatibility with most of the materials used in askarel-filled transformers and with those used in mineral-oil-filled transformers. A large number ofmaterials have been tested for compatibility with silicone transformer fluid. The tests vary fromsimple immersion to sealed-container accelerated aging to full-scale model testing. Table 3-13 isa list of many of the materials tested and found suitable in silicone transformer fluid.Table 3-13a. Transformer materials that are compatible with silicone fluidsaMetals Insulation Plastics and resins Wire enamelsCopper Kraft paper Nylon Amide-ImidePhosphor bronze Pressboard Polystyrene PolyesterAluminum NOMEX (polyamide paper) Modified acrylics AmideStainless steel QuIwTEXm (asbestos paper) Polycarbonates FORMVARCold-rolled steel MYLA.9 (polyester film) Phenolics ALKANEXtHot-rolled steel KAPTONO (polylmide film) PTFENickel Polypropylene film Silicone resinsMagnesium Cross-linked polyethylene Diphenyl oxidesZinc Wood EpoxiesCadmium Mica PolyestersDuraluminTitaniumSilverMonelTinBrass'Laboratory tests have shown these materials to be compatible with silicone fluids. However, as materials vary somewhat in compo-sition from one manufacturer to another, compatibility should be evaluated for the specific combination of materials to be used.MYLAR and KAPTON are trademarks of E.I. Du Pont de Nemours Company, Inc.QUINTEX is a trademark of Quin-T CorporationALKANEX is a trademark of General Electric CompanyTable 3-13b. Transformer materials of questionable compatibility (should be tested individually)Plastic After 30-day immersionCellulose acetate butyrate StiffensPolyacetal Stiffens and crazesPolyethylene Stress cracksLinear polyethylene Some stress cracksPolyvinyl chloride Shrinks and hardens3-12 Section 3: Transformer Design InformationCare is needed to properly select seal and gasket materials. Some plasticizers can be leached fromsome rubber formulations by silicone fluids. Because of the large number offoniulafionsavailable, individual testing of each potential seal or gasket material is recommended Table 3-14 is intended as a guide to the selection of seal and gasket materials.Table 3-14. Compatibility ratings for seal and gasket materialsNot TestingMaterial compatible Compatible recommendedNatural rubber VKEL-$'Fluorosltlcone rubberSilicone rubberNeoprene VTEFLON V"VITONsG.R.S. VEPDM VNitrile rubber "Buna-N VPolypropylene sHYPALONS.B.R. VE.P.R. vsCORPRENEe ,KEL-F is a trademark of Kellogg's Professional Products Inc.TEFLON, VfroN, and HYPALON are trademarks of EA. Du Pont de Nemours Company, Inc.CORPRENE is a trademark of ArmstrongSilicone rubber has been used as a gasket material for askarel-filled transformers. Silicone rubberand silicone transformer fluid are very similar materials. The fluid is absorbed readily into thenrbber, causing swelling and loss of physical properties. Silicone-rubber parts may be found inpower transformer bushing seals, top-cover gaskets, tap changers, filling ports, instrumentation,and other openings. If silicone nrbber is found in a transformer, it should be replaced with anonsilicone seal material that is approved for use with askarel.When choosing a dielectric material with no history of either prior use or testing with siliconefluids, compatibility testing is recommended. Dow Corning Technical Service and Developmentrepresentatives can advise you of appropriate compatibility screening and performance-testingmethods for silicone fluid.3-13 Dow Corning 561 Silicone Transformer Liquid TechnicalManual3.8 Physical Characteristics3.8.1 Vapor PressureVapor-pressure data for Dow Corning 561 SiliconeTransformer Liquid are reported in Table 3-15. The datacan be extrapolated below 1 ton- using a Cox chart, such asthe one shown in Figure 3-17. The vapor pressure may varyfrom lot to lot depending on specific conditions duringmanufacture. If the curve is extrapolated to very lowtemperatures, the vapor pressure values that fall on theextrapolated curve may be higher than are typical for thebulk fluid. These high values are due to the presence of avery small amount of low-molecular-weight silicone.A test that is often better at low temperatures than vapor-pressure measurements is a low-temperature volatility testunder vacuum. Vapor-pressure measurements begin at 2 to4 torr. Values below these have been extrapolated.Table 3-15. Vapor pressure ofDow Corninge 561Temperature Vapor pressureoc torr2312773003133223303363403453483533563583603636111621263140475481718091.5102.5113.51000I I372375136.51504-0.CL10010I.150 75 100 125150 175 200250 300Temperature, tCFigure 3-17. Cox chart for Dow Cornings 561 Silicone Transformer Liquid3. 8. 2 Volume ExpansionThe temperature coefficient of volume expansion of Dow Corning 561 Silicone TransformerLiquid is shown in Table 3-16. The relationship is shown in Figure 3-18 below. The curve may be3-14 Section 3: Transformer Design Isformationextrapolated above and below the given temperature with reasonable accuracy. As shown in thetable, the coefficient of expansion of silicone fluid is greater than those of conventionaltransformer fluids.Table 3-16. Coefficients of expansion for transformer fluidsFluidSilicone transformer fluidMineral oilAskarelCoefficient of expansion(cm3/cm.°C)0.001040.000730,00070.97.95, .93,- .91toif).89.871.181.141.10 2EC-1.06 .0CLX01.02 a,E.98 *.85 '--25.L .., ....I I a 1 I 1 .I I 1 .940 25 50 75 100 125 150 175 200Temperature, °CFigure 3-18. Changes in volume expansion and specific graity' of Dow Corning561 Si/kone Transformer Liquid u'ih temperatureClassical gas-compression versus pressure equations suggest that mineral-oil-filled and askarel-filled transformers could experience pressures in excess of their pressure ratings. However, otherfactors preclude this from happening. It appears that the transformer fluid absorbs excess gas asthe pressure increases. Although silicone fluid expands more than mineral oil or askarel, theexpansion is partially offset by its ability to absorb more gas, as shown in Table 3-17.3-15 Dow Corning 561 Silicone Transformer Liquid TechnicalMannalTable 3-17. Air solubility of transformer fluidsFluid Air solubility25°C @ 1 atmSilicone transformer fluid 16.5%Mineral oil 10.0%Askarel 5.7%Section 3.3 reports laboratory pressure data that are consistent with these concepts; pressureincreases in sealed pressure vessels were less than predicted and the pressure increasesexperienced with silicone fluids were not enough higher than askarel fluids to be of concern.In pressure-temperature experiments in actual transformers and in 81 silicone-filled transformersmonitored for a 3-year period under various service conditions, no unusual pressure or vacuunconditions developed.3.8.3 Solubility of GasesTable 3-18 reports solubility data for several gases in Dow Corning 561 Silicone TransformerLiquid at 80'C. The data are presented in terms of voltme of gas (STP) per unit volume ofsilicone transformer fluid. Figure 3-19 shows the solubility of helium and nitrogen in DowCorning 561 Silicone Transformer Liquid versus pressure.0.3Table 3-18. Gas solubility data for DowCorning 561Gas Solubility %H2 8.7CO 12CO2 73CH4 29C2H2 76C2H4 85C2HA 108N211f0I0.2[a N~gnSdIW#0.1 -UJ .. i -_ ..0 28 50 75 100 125 150 175Saturation pressure, tow"Figure 3-19. Solubility, of nitrogen and hellin inDow cordnig 5613-16 Section 3: Transformer Design Itform ation3.8.4 Viscosity-Temperature RelationshipFigure 3-20 compares the temperature-viscosity relationship of Doss, Corning 561 SiliconeTransformer Liquid with common askarels and mineral oil at various temperatures. PYRANxoLC A-13B3B-3 mid INhERTrEN' 70-30, are the only askarel formulations for which Dow Corning hasviscosity-temperature data.100010000M 10:5I L--50-25 0 25 50 75 100125Temperature, 0CFigure 3-20. Viscosity-temperature relationships for transformer fluidsIPNRANOL is a trademark of General Electric Companyt ,,R'lmu is a trdemark ofWestinghouse, Inc.3-17 Dow Coining 561 Silicone Transformer Uiqtuid Technical Manual3.8.5 Specific HeatFigure 3-21 shows how the specific heat of Dow Cornhig 561 Silicone Transformer Liquidchanges with changes in temperature. Over a normal operating temperature range the specificheat is fairly constant.0.45In0. 40.350 0.30co1-0---ý 11`ý ý I ............ .-----0-F.F0.25I I I i il.l I i i0 50 100 150 200Temperature, °CFigure 3-21. Specific heat of Dow Corning9 5613.8.6 DensityThe change in density of Dow Corning 561 Silicone Transformer Liquid with respect totemperature can be determined from Figure 3-18 since:p = Specific gravityx p,,,,,Alternatively, density can be determined using the following equation:Pr = P2s(I + 0.00036(T- 25°C))where p = 0,9572 g/mL3-18 Section 3: Transformer Desirg Information3.9 LubricityPolydimethylsiloxane (PDMS) is usually not recommended for use as a metal-to-metal lubricant.It lacks the lubricity required for many mechanical applications that involve sliding frictionbetween metals. However, when rolling friction is involved, Dow Corming 561 SiliconeTransformer Liquid has good lubricity and good load-carrying capacity between many commoncombinations of materials.PDMS fluid is one of the best lubricants for fiber and plastic gears or bearings constructed ofnatural and synthetic rubber, polystyrene, phenolics, and most other plastics. However,compatibility with each these types of materials should be checked individually.Tables 3-19, 3-20, and 3-21 contain a list of metal combinations that are rated as "poor,""questionable," and "good," respectively, when used with Dow Corningj 200 fluid by DowComing as a lubricant. These ratings are merely for comparison: no actual measurements havebeen made of the absolute lubricating properties ofDow Corning 561 Silicone TransformerLiquid. The data result fioom a simple sliding test between two metal plates.Every application that uses silicone fluid as a lubricant is different, and each combination shouldbe thoroughly tested before any final design recommendations are made.Table 3-19. Metal combinations rated "poor" when lubricated with Dow Comingn 200 fluidSlider Plate Slider Plate Slider PlateAluminumAluminumBabbittCadmiumSteelCadmiumManesiumSilverCold-rolled steelBabbittBabbittCopperMagnesiumStainless steelTinBabbittBrassChromiumCopperMagnesiumSilverTinZincCadmiumMagnesiumSilverTin BrassCadmiumMagnesiumZincZincBrass Babbitt Magnesium SilverCopper Stainless steelStainless steel ZincBabbittChromiumCopperMagnesiumSilverStainless steelBronzeBrassMagnesiumStainless steelTinNickelBrassMagnesiumNickel3-19 Dow Corming 561 Silicone Transformer Liquid Technical ManualTable 3-20. Metal combinations rated "questionable" when lubricated with Dow Comring 200 fluidSlider Plate Slider Plate Slider PlateAluminum Stainless steel Chromium Brass Copper Stainless steelSilver Cadmium Magnesium AluminumTin Chromium BabbittBabbitt Aluminum Copper CopperBrass Magnesium Magnesium MagnesiumSilver Nickel Nickel BabbittChromium Aluminum Sliver CadmiumBabbitt Stainless steel CopperTin Stainless steelZinc ZincCold-rolled steel Aluminum Tin SilverStainless steelTable 3-21. Metal combinations rated "good" when lubricated with Dow Corning? 200 fluidSlider Plate Slider Plate Slider PlateAluminumBrassChromiumCopperMagnesiumNickelZincCadmiumAluminumBabbittChromiumCadmiumChromiumCopperNickelSilverStainless steelSteelTinMagnesium CadmiumChromiumNickelTinNickel AluminumChromiumSliverTinBabbittBrassCadmiumChromiumNickelSliverSteelZincSilverZincCold-rolled steelBrassAluminumBrassCadmiumChromiumNickelTinZincCadmiumGraphitarNickelNylonAluminumBabbittBrassChromiumCopperNickelStainless steelSteelTinZincCopperBronzeAluminumBabbittCadmiumChromiumCopperNickelNylonSilverSteelZincAluminumBabbittBrassCadmiumChromiumCopperMagnesiumNickelSilverTinZincTin AluminumBabbittChromiumCopperNickelStainless steelSteel3-203.-20 Section 3: Transformer Design Information3.10 Retrofili Considerations3.10.1 Material and Component Compatibilio,When retrofilling a transformer for final fill with silicone fluid, consideration should be given tothe compatibility of the materials and devices within the transformer with the new fluid. Theprimary areas to consider involve the insulation materials, sealing and gasket materials, and anymoving parts.Silicone transformer fluid has acceptable compatibility with most of the materials used in askarel-filled and mineral-oil-filled transformers. A large number of materials have been tested forcompatibility with silicone transformer liquid. Section 3.7, Material Compatibility, discussescompatibility issues in more detail and provides lists of compatible materials. Compatibility ofgasket materials is more often of concern than insulation materials and can require that gaskets bechanged. A list of compatible gasket materials is also provided in Section 3.7.Lubricity is a key compatibility consideration if moving parts are present. Although mineral oil isusually an excellent lubricant, the efficacy of silicone fluid as a lubricant depends on specificcircumstances. Considerations involve whether the parts in f-iction are metal or plastic, whichmetal or plastic is involved, and whether the parts involve sliding or rolling friction. Section 3.9,Lubricity, provides detailed information on the lubricity of silicone transformer fluid. Thisinformation--along with knowledge of the application such as the expected frequency ofoperation of a device like a switch or tap changer-will help determine the compatibility of thesilicone transformer fluid.The compatibility of oil-inmersed load-break devices with silicone transformer fluid has recentlybeen tested. Results show the acceptability of silicone fluid truder arcing conditions. Specific dataare given in Section 3.5, Load-Break Switching Performance.It is strongly recommended that retrofills be undertaken only by experienced transformer servicecompanies and only after consultation with the transformer manufacturer.3.10.2 Temperature RiselHeat TransferThe effectiveness of a fluid as a heat-transfer medimn is dependent not only on viscosity, but alsoon the following properties:" Density* Thennal conductivity* Heat capacity" Coefficient of thermal expansionThe effect of these properties is dependent on the heat-transfer mechanism within thetnansforner-whether it is free convection, forced convection in laminar flow, or forcedconvection in turbulent flow.Although the higher viscosity of the silicone transformer fluid may tend to reduce the liquid flow,the increased density difference between cool and warm fluid will increase thermal siphoning infree-convection flow in the transformer. This observation is supported by practical experience intransformers. Table 3-22 shows heat-run data from two identical new transformers. One3-21 Dow Coniing 561 Silicone Transformer liquid TeclnicalMarnaltransformer contained IIERTEEN, a Westinghouse askarel, and the other contained DowCorning? 561 Silicone Transformer Liquid.Table 3-22. Heat-run data for transformer fluids in 2500 kVA, 13.8 kV, Delta 450 LV WYE transformerTemperatureratingbC55655565Transformer fluidINERTEEN liquidINERTEEN liquid561 Transformer fluid561 Transformer fluidLoadpercent100100100100Loadlosseswatts2790028000Rise In windings byresistance measurementsHV. L.V.50.90 50.1060.00 60.0046.88 46.0357.52 57.28Top fluldriseCc49.9086.0053.0061.00The results show that, in spite of differences in winding temperature distribution, the heat-transferperformance for Dow Corning@ 561 Silicone Transformer Liquid is comparable to INERTEEN forthis particular design. Table 3-23 shows heat-nm data for two other transformer designs; bothdesigns were originally filled with askarel, drained, and refilled with silicone fluid.Table 3.23. Heat-run data for alternative transformer designsAskarel Silicone2240 WVA, 3/60 13800 -480YPrimary rise. =C 61.5 62.7Secondary rise, "C 61.7 65.9Top fluid rise, °C 60.0 67.22000 WVA, 3/60 13800-480YPrimary rise, *C 57.3 54.0Secondary rise, 'C 53.8 57.5Top fluid rise, 'C 51.8 58.3Table 3-24 lists the heat-transfer characteristics of Dow Corning 561 Silicone TransformerLiquid compared to other commonly used transformer fluids.Table 3-24. Heat-transfer properties of transformer fluidsSpecific Coefficient of Thermal HeatFluid Viscosity gravity expansion conductivity capacitycentistokes 1/=C cal/(s.cm2-*C/cm) cal/g.'CDow Comingo 561 50. 0.960 0.00104 0.00036 0.363AROCLOn 1242 17.2 1.380 0.00119 0.00023 0.290AROCLOR 1254 46.4 1.540 0.00123 0.00021 0.260WEMCO CTm (mineral oil) 15. 0.898 0.00073 0.00036 0.A8AROCLOR is a trademark of Monsanto Chemical CompanyWEMCO C is a trademark of Westinghouse, Inc.Historically the vast majority of transformer retrofills have involved replacing askarel withsilicone transformer fluid. More recently the retrofill of mineral-oil-filled transformers withsilicone fluid has increased. In the retrofill of mineral-oil-filled units some consideration shouldbe given to resulting temperature-rise performance. Depending on the transformer design andloading of the unit, it may be possible to see higher than original design rating temperatures of thefluid. The fluid itself is unaffected by typical oveitemperatures. However, the aging rate of3-22 Section 3: Transformer Design Informationconventional insulation materials, such as cellulose, can be affected by operation at temperatureshigher than design limits.Designers can compensate for the higher temperatures by adjusting loading levels such that thedesign temperature use is not exceeded or by adding external radiator fans to increase cooling ofthe fluid. Mineral-oil-filled transformers retrofilled with silicone fluid that previously operated atless than fall load will be less likely to exceed design temperatures.The heat-transfer performance of silicone transformer fluid is highly dependent on thetransformer design; some designs are better optimized to take advantage of the heat-transfercharacteristics of the fluid. For example, if a layered-winding design is used, vertical channelswill maximize the thermal siphoning effects produced by the high coefficient of expansion. Discwindings, however, are more complex and can obstruct the vertical free flow of the liquid.Table 3-25 provides comparative fluid temperature rises of both mineral-oil-filled and silicone-filled transformers in a test station. The transformers were tested both as-new and afterretrofilling with the silicone fluid. Two different size transformer pairs of similar design wereused in the test. Pair 1 (consisting of units no. 1 and 2) was initially filled with mineral oil (21gallons each) and operated at 25 kVA, 2400/4160Y, 2401480 with 1.6% and 1.7% impedance.Pair 2 (consisting of units no. 3 and 4) was initially filled with silicone fluid (29 gallons each) andoperated at 50 WVA, 2400/4160Y, 240/480, with 1.8% impedance.Table 3-25. Temperature versus load data for 25 and 50 kVA transformersTransformer Pair No. 1-25 kVA Transformer Pair No. 2-50 kVATested as received with mineral oil Tested as received with Dow Cornin9. 561Unit 1 Unit 2 Unit 3 Unit 4Load Amb Top oil Oil Load Amb Top oil Oil Load Amb Top oil Oil Load Amb Top oil Oil% °C 0C rise % C "C rise % 0C tC rise % Cc °C rise75 28 52 24 75 29 63 34 75 26 56 30 75 26 59 33100 30 69 39 100 30 72 42 100 28 80 52 100 26 82 54125 31 65 34 125 31 69 38 125 31 92 61 125 31 94 63150 32 71 39 150 32 73 41 150 28 110 82 150 28 108 80175 23 75 52 175 23 77 54 175 24 120 96 175 24 119 95Tested after retrofill with Dow Coming 561 Refrofilled with mineral oil Rerun with Dow ComingY561Unit 1 Unit 2 Unit 3 Unit4Load Amb Top oil Oil Load Amb Top oil Oil Load Amb Top oil Oil Load Amb Top oil Oil% tC C rise % cC 0C rise % 'C °C rise % 'C 'C rise100 4 39 35 100 4 37 33 100 4 44 40 100 4 42 38136 14 60 46 136 14 57 43 126 14 68 54 126 14 69 55162 16 63 47 162 16 63 47 153 15 91 76 175 30 105 75187 20 82 62 187 20 82 62 175 30 103 73 175 30 105 753-23 Dow Corning 561 Silicone Trausformer Liquid Teclnical Manual3.10.3 Fire Safeoy ConsiderationsWhen retrofilling a mineral-oil-filled transformer with silicone fluid there will always be someresidual oil left in the unit, This residual oil is soluble to a certain extent in silicone transformerfluid and can decrease the flash and fire points of the fluid. Table 3-26 provides data on the effectof various levels of residual mineral oil on the flash and fire points of the transformer fluid.The data suggest that a maximmn contaminant level of 3% is allowable before the flash and firepoints of the silicone fluid decline significantly. Procedures such as rinsing the drained tank withsilicone fluid prior to final filling can minimize residual mineral oil. Experience has shown thatretrofilled mineral-oil transformers can achieve "less-flammable" status given sufficient care inremoving residual mineral oil firom the tank.Table 3-26. Effect of mineral oil contamination on flash and firepoints of silicone transformer fluidMineral oil level Flash point Fire point% °C cc0 322 >3431 241 >3432 229 :'3433 202 3325 193 24110 179 2073-24 Setion 4: Speci/fing 561 Transformer FluidSection 4: Specifying 561 Transformer FluidSection Content4.1 Model Specification ......................................................................................................... 4-14.2 Applicable Standards ....................................................................................................... 4-54.2.1 1996 National Electrical Code ......................................................................... 4--5Section 450-23 ............................................................................................................ 4-54.2.2 1996 National Electrical Safety Code .................................................................... 4-6Section 15. Transformers and Regulators ........................................................................ 4-64.2.3 ASTM Standards .................................................................................................... 4-74.2.4 IEE E G uide ........................................................................................................... 4-74.3 Product L istings ............................................................................................................... 4-84.3.1 Factory Mutual Approval ....................................................................................... 4-84.3.2 UL Classification Marking ................................................................................... 4-84.1 Model SpecificationDow Corning technical service engineers have compiled a model that specifiers can use todevelop complete specifications for transformer fluids. The model is in outline form and is foundon the following three pages. It includes references to the most common publications, standards,and classifications used to characterize the perfornimace and safety of transformer fluids.4-1 Dow CornLingt9. 561 Silicone Transformer Liquid Tecimical ManualSection 16XXXTrans former Liquids1.0 Part 1-General1.01 Section IncludesA. Mineral OilB. Less-Flammable Liquids1.02 ReferencesThe publications listed below form a part of this specification to the extent referenced. Thepublications are referred to in the text by the basic designation only.American Society for Testing and Materials (ASTM)ASTM D 117 1989 Electrical Insulating Oils of Petrolemn OriginASTM D 445 1988 Test Method for Kinematic Viscosity of Transparent and OpaqueASTM D 2161 1987 Standards Practice for Conversion of Kinematic Viscosity to SayboltUniversal Viscosity or to Saybolt Furol ViscosityASTM D 2225 1992 Standard Methods Testing Silicone Fluids Used for ElectricalInsulationASTM D 3455 1989 Test Methods for Compatibility of Construction Material withElectrical Insulating Oil of Petroleum OriginASTM D 3487 1988 Mineral Insulating Oil Used in Electrical ApparatusASTM D 4652 1992 Standard Specification for Silicone Fluid Used for Electrical InsulationFactory Mutual Engineering and Research Corporation (FM)FM P7825 1993 Approval GuideInstitute of Electrical and Electronics Engineering (IEEE)ANSIJJEEE C37.71 1984 (R 1990) Thr'ee-phase, Manually Operated Subsurface Load-Interrupting Switches for Alternating Current SystemsANSI/IEEE C57.I1 1989 IEEE Guide for Acceptance of Silicone Insulating, Fluid andIts Maintenance in TransformersNational Fire Protection Association (NFPA)NFPA 70 1996 National Electrical CodeNEC 450-23 Less-Flammable Liquid-Insulated TransformersNEC 450-26 Oil-Insulated Transformers Installed IndoorsNEC 450-27 Oil-Insulated Transformers Installed OutdoorsUnderwriters Laboratories Inc. (UL)Gas and Oil Equipment Directory4-2 Section 4: Specj.tjng 561 Transformer FluidEOUV Dielectric MediumsEOVK Transformer Fluids1.03 Submittals1.03.1 DataA. Submit Underwriters Laboratories Category EOVK Classification Marking asprovided by transformer fluid manufacturer.1.03.2 ReportsA. Submit technical report on load break switch testing in specified transformer fluid.1.04 Operation and Maintenance Data1.04.1 Include transformer liquid manufacturer's recommended procedures for(sampling/storage/handlingldisposal/recycling).1.04.2 Submit transformer fluid manufacturer's operation and maintenance manual.2.0 Part 2-Products2.01 Nonflammable Liquids2.01.1 Do not provide nonflammable transformer liquids including askarel and insulatingliquids containing polychlorinated biphenyls (PCBs) and tetrachloroethylene(perchloroethylene), chlorine compounds, and halogenated compounds.2.02 Mineral Oil2.02.1 Liquid shall comply with requirements as set forth in ASTM D 3487, Type II, astested in accordance with ASTM D 117 test procedures.2.03 Less-Flammable Liquids2.03.1 Less-flammable liquids shall have a fire point not less than 300°C per NFPA 70.2.03.2 Shall comply with requirements set forth in ASTM D 4652 and tested per ASTM D2225.2.03.3 The fluid shall be approved per Factory Mutual P7825. Total heat release rate shallnot exceed 150 kW/m2.2.03.4 The fluid shall be classified by Underwriters Laboratories as a dielectric mediun perUL category EOUV. The fluid shall also be classified as a transformer fluid per ULcategory EOVK. Category EOVK classification marking use restrictions formaximum allowable fault energy shall not be less than 700,000 12t for 45 kVAtransformers ranging to 14,000,000 ft for 10,000 kVA transformers.2.03.5 Less-flammable transformer liquids used as a switching medium for liquid-immersedtype load-break switches shall have load-switching tests performed in accordancewith ANSIIIEEE C37.71. Fire point and dielectric strength shall meet or exceedspecified values in C57.1 11 after 120 energized load-switching operations, includingfill inductive load switching, and load currents up to 300 amperes at 15 kV.4-3 Dow Corming 561 Silicone Transformer Liquid TechnicalManual2.03.6 Compatibility of less-flammable transformer liquids with sealing and gasketingmaterials shall be proven by tests conducted in accordance with ASTM D 3455.2.03.7 Liquid viscosity shall not exceed 100 minm2/s at 0°C as tested per ASTM D 445, D2161.3.0 Part 3-Execution3.01 Installation3.01.1 Electrical installations shall conform to NFPA 70 and to the requirements specifiedherein.3.01-2 Indoor Installations3.01.2.1 Mineral-oil-insulated transformers shall be installed per NEC Section 450-26.3.01-2-2 Less-flanunable liquid-insulated transformers shall be installed per NECSection 450-23 and in compliance with either Factory Mutual listingrequirements or the UL Classification Marking of the liquid.3.01.3 Outdoor Installations3.01.3.1 Mineral-oil-insulated transformers shall be installed per NEC Section 450-27.Safeguards and clearance requirements shall be based on Factory Mutual LossPrevention Data Sheet 5-4/14-8.3.01.3.2 Less-flammable liquid-insulated transformers shall be installed per NECSection 450-23 and in compliance with either Factory Mutual listingrequirements or the UL Classification Marking of the liquid.4-4 Section 4: Speci6ying 561 Transbformer Fluid4.2 Applicable StandardsMost of the applicable standards for transformer fluids are listed in the reference section of themodel specification in the preceding text. Complete copies of these references can be obtainedfrom the issuing organization.4.2.1 1996 National Electrical CodeThe National Electrical Code (NEC), Section 450-23, provides requirements for the installationof less-flammable liquid-filled transformers. The NEC now reflects acceptance of less-flammablefluids for outdoor transformer installations as well as indoor installations. The National ElectricalCode can be requested from the National Fire Protection Agency (NFPA) by contacting:National Fire Protection Agency1 Batterymarch ParkP.O. Box 9146Quincy, MA 02269-9959Telephone: (800) 344-3555Relevant text from the 1996 National Electrical Code is printed below.Section 450-23Less-Flammable Fluid-Insulated Transformers. Transformers insulated with listed less-flammable fluids having a fire point of not less than 3001C shall be permitted to be installed inaccordance with (a) or (b).(a) Indoor Installations. In accordance with (1), (2), or (3):(1) In Type I or Type I1 buildings, in areas where all of the following requirements are met:a. The transformer is rated 35,000 volts or less.b. No combustible materials are stored.c. A liquid confinement area is provided.d. The installation complies with all restrictions provided for in the listing of the liquid.(2) With an automatic fire extinguishing system and a liquid confinement area, provided thetransformer is rated 35,000 volts or less.(3) In accordance with Section 450-26.(b) Outdoor Installations. Less-flammable liquid-filled transformers shall be permitted to beinstalled outdoors attached to, adjacent to, or on the roof of buildings, where installed inaccordance with (1) or (2):(1) For Type I and Type II buildings, the installation shall comply with all restrictions providedfor in the listing of the liquid.(FPN): Installation adjacent to combustible material, fire escapes, or door and window openingsmay require additional safeguards such as those listed in Section 450-27.(2) In accordance with Section 450-27.4-5 Dow Corninog 561 Silicone Transformer Liquid TechniealMantal(FPN No. 1): Type I and Type II buildings are defined in Standard on Types ofBuiildingConstruction, NFPA 220-1995.(FPN No. 2): See definition of "Listed" under Article 100.4.22 1996 National Electrical Safety CodeRelevant text from the 1996 National Electrical Safety Code (NESC) is printed below. Thesesections also recognize the use of less-flammable transformer fluids. Copies of the NESC can berequested from IEEE at the address shown in Section 4.2.4.Section 15. Transformers and Regulators152. Location and Arrangement of Power Transformers and RegulatorsA. Outdoor Installations1. A transformer or regulator shall be so installed that all energized parts are enclosed orguarded so as to minimize the possibility of inadvertent contact, or the energized partsshall be isolated in accordance with Rule 124. The case shall be grounded in accordancewith Rule 123.2. The installation of liquid-filled transformers shall utilize one or more of the followingmethods to minimize fire hazards. The method to be applied shall be according to thedegree of the fire hazard. Recognized methods are the use of less flammable liquids,space separation, fire-resistant barriers, automatic extinguishing systems, absorptionbeds, and enclosures.3. The amount and characteristics of liquid contained should be considered in the selectionof space separation, fire-resistant barriers, automatic extinguishing systems, absorptionbeds, and enclosures that confine the liquid of a ruptured transformer tank, all of whichare recognized as safeguards.B. Indoor Installations1. Transforners and regulators 75 kVA and above containing an appreciable amount offlammable liquid and located indoors shall be installed in ventilated rooms or vaultsseparated from the balance of the building by fire walls. Doorways to the interior of thebuilding shall be equipped with fire doors and shall have means of containing the liquid.2. Transfornmers or regulators of the dry type or containing a nonflammable liquid or gasmay be installed in a building without a fireproof enclosure. When installed in a buildingused for other than station purposes, the case or the enclosure shall be so designed that allenergized pails are enclosed in the case grounded in accordance with Rule 123. As analternate, the entire unit may be enclosed so as to minimize the possibility of inadvertentcontact by persons with any pail of the case or wiring. When installed, the pressure-reliefvent of a unit containing a nonbiodegradable liquid shall be frinished with a means forabsorbing toxic gases.3. Transformers containing less flammable liquid may be installed in a supply stationbuilding in such a way as to minimize fire hazards. The amount of liquid contained, thetype of electrical protection, and tank venting shall be considered in the selection ofspace separation from combustible materials or structures, liquid confinement, fire-resistant barriers or enclosures, or extinguishing systems.4-6 Section 4: Specfying 561 Transformer Fluid4.2.3 ASTM StandardsThe primary ASTM standards of interest in specifying silicone transformer fluids are:" ASTM D 4652-92--"Standard Specifications for Silicone Fluid Used for Electrical Insulation,"1996Annual Book of ASTM Standards, Vol. 10.03, Electrical Insulating Liquids and Gases;Electrical Protective Equipment." ASTM D 2225-92--"Standard Methods of Testing Silicone Fhlids Used for ElectricalInsulation," 1996 Annual Book ofASTM Standards, Vol. 10.03, Electrical Insulating Liquidsand Gases; Electrical Protective Equipment.Copies of these ASTM standards (and other ASTM standards) can be obtained by contacting:ASTM1916 Race StreetPhiladelphia, PA 19103-1187Telephone: (215) 299-5400Fax: (215) 977-96794.2.4 IEEE GuideThe IEEE Guide for Acceptance of Silicone Insulating Fluid and Its Maittenance inTransfonners (IEEE C57-111-1989) can be obtained from the Institute of Electrical andElectronics Engineers (IEEE) by contacting:IEEE345 East 47th StreetNew York, NY 100174-7 Dow Corningt 561 Silicone Transformer Liquid Techikcal Manual4.3 Product ListingsAmong the National Electrical Code requirements for less-flammable fluid-filled transformers isthat the fluid must be "listed." According to the NEC, Section 70, the term 'listed' refers to:Equipment or materials included in a list published by an organization acceptable to the authorityhaving jurisdiction and concerned with product evaluation, that maintains periodic inspection ofproduction of listed equipment or materials, and whose listing states either that the equipment ormaterial meets appropriate designated standards or has been tested and found suitable for use in aspecified manner.Currently two major agencies have established listings for less-flammable liquids per the NEC:Factory Mutual Research Corporation(FM) and Underwriters Laboratories (UL). However, eachhas developed somewhat different requirements. UL criteria are based on explosion preventiop ofthe transformer tank. FM requirements involve both preventive protection of the transformer andprotection of the facility structure, which are based on the burning characteristics of the liquid.Specific applications can lend themselves to the use of one or the other listing. Normally, eitherlisting is acceptable for compliance with the NEC.Additional information regarding product listings is available UL, FM, and Dow Corning.4.3.1 Factoy Mutual ApprovalDow Corning 561 Silicone Transformer Liquid is approved by Factory Mutual ResearchCorporation and can be used indoors without additional fire protection when installed incompliance with NEC Section 450-23 and the restrictions of the FM listing. Qualification for FMapproval includes testing of the rate of heat release when the fluid is involved in a fire. Heatrelease is analyzed with respect to the ability of the building to withstand a fire.In testing performed by FM, Dow Corning 561 Silicone Transformer Liquid produced thelowest heat release rates of approved materials. See Table 4-1.Table 4-1. Heat release rates for Dow Corning 561Heat release mechanism Heat release ratekWlmrRadiative 25Convective 53Total 784.3.2 UL Classification MarkingDow Corning 561 Silicone Transformer Liquid is classified by Underwriters Laboratories asboth a "dielectric medium and as less flammable per NEC 450-23." The material is also classifiedas a less-flammable liquid in compliance with the National Electrical Code, when used in 3-phasetransformers with the following restrictions:Use only in 3-phase transformers with tanks capable of withstanding an internal pressure of 12psig without rupture.4-8 Section 4: Spec#Wlfng 561 Transformer Fluid" Pressure-relief devices must be installed on the transformer tank in accordance with Table 4-2to limit pressure build-up and prevent tank rupture from gas generation under low currentarcing faults.* Overcurrent protection having ft characteristics not exceeding the values in Table 4-2 must beprovided for the primary circuit to limit possible high-current arcing faults. If the fuse isdesigned to vent during operation (such as an expulsion fuse), it shall be located external to thetransformer tank.Table 4-2. Pressure relief and overcurrent protection requirements for silicone-filledtransformersTransformer rating Pressure.relief ckVA SCFM@15p45 3575 35112.5 35150 50225 100300 100500 350750 3501000 3501500 7002000 7002500 50003000 50003750 50005000 to 10.000 5000'Opening pressure: 10 psig maximumb Addiuonal requirement to that in Section 450-3 of 1993 NECapacity8iSigapaeityspslgOvercurrent protectionbA~s700,000800,000900,0001,000,0001,200,0001,400.0001,900.0002,200,0003.400,0004,500,0006,000,0007,500,0009,000,00011,000,00014,000,0004-9 Section 5: M'ateriaI HandlingSection 5: Material HandlingSection Content5.1 S torage ............................................................................................................................. 5- 15.2 B ulk H andling .................................................................................................................. 5-25.3 Sam pling .......................................................................................................................... 5-25.3.1 Sampling from Shipping Containers ..................................................................... 5-25.3.2 Sampling from Apparatus .................................................................................... 5-55.4 Pum ping ........................................................................................................................... 5-65.5 Filling Transform ers ........................................................................................................ 5-75.5.1 Filling under V acuum ............................................................................................ 5-75.5.2 Filling w ithout Vacuum ......................................................................................... 5-75.6 V acuum D egasification .................................................................................................... 5-95.7 Silicone Solutions for Mineral Oil Foaming ........................................................... 5-115.8 Paint and Paintability ..................................................................................................... 5-135.8.1 Surface Preparation ............................................................................................. 5-135.8.2 Paint A dditives ..................................................................................................... 5-145.1 StorageAs is recommended practice for all high-purity dielectric fluids, when handling, storing,sampling, and inspecting silicone transformer fluid and when operating silicone-filledtransformers, every precaution should be taken to protect the silicone fluid from exposure to highhumidity or moisture contamination. Shipping drums should be stored indoors in an areaespecially selected for this purpose. If it is necessary to store drums or cans containing siliconetransformer fluid outdoors, they should be stored in a covered area or otherwise protected fromthe weather and direct contact with water. In exposed locations, drums should be stored with thebumgs down to prevent collection of water around the bung. Drnus should be kept sealed until thefluid is actually needed. Partially empty drums should be tightly resealed and stored in the samemanner as above.Bulk storage of Dow Corning 561 Silicone Transformer Liquid can be protected from excessmoisture by an inert gas (nitrogen) or dry-air blanketing system or a desiccant vent dryer system.The storage tank design, materials of construction, and moisture protection systems should beevaluated to determine the best arrangement at each site prior to delivery.Bulk storage tanks should be mounted on piers above the ground and easily accessible for leakinspection. There should be a curb or dike on the ground around the tanks to contain any spills orleaks. Check with state mid local agencies to determine exact containment requirements in yourarea,Stainless steel is recommended as the best material of construction for piping and storage tanks.Carbon steel is adequate for piping, and carbon steel with a zinc primer or an epoxy paint-on5-1 Dow Corning 561 Silicone Transformer Liquid Teclmical Mantialcoating or liner is suitable for storage tanks. Fiberglass and aluminum storage tanks have alsobeen used successfiflly. Because of the variety of binders and alloys available, we recommendtesting the specific material of construction for suitability prior to use.The useful lifetime of Dow Cornine 561 Silicone Transformer Liquid is virtually unlimitedwhen it is stored properly. However,faihlre to properly store and protect drmns or bulk storageof silicone transform erfluid as specified above can result hi contamination by water.5.2 Bulk HandlingLoading of Tank Trucks-Proper preparation of tank trucks for receiving Don, Corning ,61Silicone Transformer Liquid is critical. Tank trucks must be clean and moisture-free. Prior toloading, tank trucks are usually purged with dry air or nitrogen to protect the fluid from absorbingmoisture from humid air inside the tank. Once loaded, the tank truck is then pressurized toapproximately 5 psig. This helps to prevent the vacuum relief valve on tank truck firom"breathing" outside air. Breathing is usually caused by significant outside temperature variationsthat will affect the relative humidity of the air within the tank truck.Tank Truck Transfer-To completely protect the product from moisture during producttransfer, the receiving site should plan the best way to vent the tank ruck. A common practice isto vent the tank out of the dome m-ea, as would be done on typical product transfers. However,this procedure will affect the product moisture specification, especially during a long transfer.There are two methods of providing ample venting to the tank truck while keeping moistureunder control. One way is to simply provide clean, dry compressed air or nitrogen back to thetank truck. This method can be used to unload the tank truck or it can be used in conjlnction witha transfer pump.The second method employs a closed-loop venting system. Here, the tank truck vent is comnectedto the storage tank vent to equalize pressure during the transfer. Making proper connections andusing the correct vent hose size is very important so as not to restrict the venting between thestorage tank and tank truck. Once the vents have been connected and the lines vent valvesopened, the product can then be piunped into the storage tank.5.3 Sampling5.3.1 Sampling from Shipping ContainersThe dielectric strength of any dielectric fluid is affected by small amounts of certain impurities,particularly water. To avoid contamination and to obtain accurate test results, it is important thatgreat care be taken in obtaining and handling samples. Poor dielectric test results that have beenreported in the field have often been found, on investigation, to have resulted largely firomcareless handling. The following instructions, based on specifications from the American Societyfor Testing Materials (ASTM), must be followed to ensure accurate results.Sample Bottle-The sample container should be made of glass, of at least 16 oz capacity, andshould be clean and dry. Glass bottles are preferable to a metal container since glass may beexamined to verify that it is clean. It also allows visual inspection of the silicone transformer fluidfor separated water and solid impurities before testing.5-2 Section 5: Material HandlingThe clean, dry bottle should be thoroughly rinsed with Stoddard solvent (or another suitablesolvent) that has previously withstood a dielectric test of at least 25 kV in a standard test cup andthen allowed to dain thoroughly. It is preferable to heat both the bottle and cap to a temperatureof 100°C (2127F) for 1 hour after draining. The bottle should then be tightly capped and the neckof the bottle dipped in melted paraffin to seal.Glass jars with rubber gaskets or stoppers must not be used. Silicone transformer fluid may easilybecome contaminated from the sulfu- in natural rubber. Polyethylene-lined caps are preferred.Thieves for Sampling-A simple and convenient"thief" can be-made for sampling 55-gallondrums. The dimensions should be as shown inFigure 5-1. Three legs equally spaced around thethief at the bottom and long enough to keep theopening 'Is inch from the bottom of the drunbeing sampled will help secure a representativesample. Two rings soldered to opposite sides ofthe tube at the top will allow you to convenientlyhold the thief by slipping two fingers through therings, leaving the thumb free to close the opening.In an emergency, a 36-inch-long piece of tubingcan be used. For tank trucks and railcars, a thiefthat uses a h'ap at the bottom may be used.The thief should be capable of reaching thebottom of the container, and the sample should betaken with the thief not more than V/s inch fromthe bottom. Thieves should be cleaned before andafter use by rinsing with Stoddard solvent oranother suitable solvent; be sure that no lint orfibrous material remains on them. When not inuse, they should be kept in a hot, dry cabinet orcompartment at a temperature not less than37.80C (100F) and stored in a vet ical position ina rack having a suitable drainage receptacle at thebase.1 1/4"Samples should not be taken from containers that II..1,have been moved indoors until the silicone fluid ^lV 1/8."is at least as warm as the surrounding air. Enough 3/8' --go-moisture can condense firom a huimid atmosphere Figure 5-1. Drum dthef and common technon the cold fluid surface to affect the insulating for sampling drumsproperties. Sampling silicone transformer fluidfrom containers located outside is undesirable because of the possibility of moisturecondensation; it should be avoided whenever possible. (Samples should never be taken in therain.)iqueRecommended Procedure-The drums to be sampled should be arranged in a line with bungsup and then nunbered. The bung seals should be broken and the bung removed and laid with theoil side up beside the bungholes. The unstoppered sampling container can be placed on the5-3 Dow Coning* 561 Silicone Transformer Liquid TechnicalManualopposite side of the bungholes. The top hole of the thief should be covered with the thumb, thethief thrust to the bottom of the container and the thumb removed. When the thief is filled, the tophole should be re-covered by the thiunb, the thief quickly withdrawn, and the contents allowed toflow into the sample container.The lower holes should not be closed with the fingers of the other hand. The free hand should notbe used to guide the stream of silicone transformer fluid except by touching the thief, and thisonly when necessary. The silicone transformer fluid should not be allowed to flow over the handor fingers before it flows into the sampling container.When the sampling container is full, it should be closed quickly. The drum bung should bereplaced and tightened, and the sampling container, now closed and under cover, should be takento the testing laboratory as quickly as possible. After use, all thieves and sampling containersshould be thoroughly cleaned as outlined above.Tank trucks and railcars of silicone transformer fluid should be sampled by introducing the thiefthrough the manhole on top of the car, the cover of which should be removed carefully so as notto contaminate the fluid with dirt. The sample should be taken as near as possible to the bottom ofthe tank car. Atmospheric precipitation should be excluded while sampling.It may also be possible to sample the fluid through a drain valve on the bottom of the tank car.This may be done after allowing a volume of fluid equal to the volume of the drain valve to pass.This will help ensure that you obtain a representative sample.When separate samples are being taken from a consignment or pail of a consignment, care shouldbe taken to prevent contamination of the samples. A separate thief should be used for eachsample, or the thief previously used should be well drained and then thoroughly rinsed with fluidfrom the next container to be sampled. Any silicone transformer fluid used for rinsing should bediscarded before the next sample is taken. Enough thieves should be provided to ensure thoroughdrainage of each thief after rinsing with silicone transformer fluid before using it to withdraw theactual sample. Two thieves are sufficient if only a few samples are involved; for a large numberof samples (for example, sampling a carload of dnunmed silicone transfotmer fluid), six or morethieves are desirable.When one average sample of a consignment or batch is being taken, the same thief may be usedthroughout the sampling operation, and it is not necessary to rinse the thief with fluid beforeobtaining any of the portions that go to make up the total average sample.Quantity of Sample-It is recommended that one 16-oz bottle of silicone fluid be taken as asample for dielectric tests, and a 1-quait sample be taken when complete physical and chemicaltests are to be made. At least one sample should be taken from each tank car of silicone fluid. Onesample may be taken from each drum or, if desired, a composite sample may be made bycombining samples from all drums, provided all drums are airtight. When the bung is firstloosened, you should hear a hissing sound, indicating that the chum is airtight. If the test of thecomposite sample is unsatisfactory, individual samples from each of the dnuns must be tested.When drums have been stored exposed to the weather, a sample from each drum should be tested.The sample should be examined for separated water. If water is noted, refer to Section 6.2,Contamination. If water appears in samples taken from a tank car, follow the same procedure.5.3.2 Sampling fiom Apparatus5-4 Section S: Material HandlingWhen taking samples of silicone transformer fluid from apparatus in which a thief cannot beused, use the sampling valve and follow the procedure outlined above as far as is practical.Care should be taken to procure a sample that fairly represents the silicone transformer fluid atthe bottom of the tank. A sufficient amount of fluid should be drawn off before the sample istaken to ensure that material in the sampling pipe is not sampled. For this reason, the valve andthe drain pipe should be sufficiently small to be emptied with convenience and yet sufficientlylarge to allow an even flow of fluid and avoid cloging by sediment. Use of 1/4-inch pipe andvalves is recommended. This, of course, may be separate from the drain pipe and valve or it maybe connected to the drain valve with a suitable reducer.It is of the utmost importance that the sample of silicone fluid represents the actual condition ofthe silicone fluid in the apparatus. Every precaution should be taken to keep the sample andcontainer free from contamination by impurities or moisture during the sampling process. If theapparatus is installed outdoors, care must be taken to prevent contamination of the sample byprecipitation.A glass bottle is recommended as a sample container, so that any water present may readily bevisible. If the sample contains separated water, it is not suitable for dielectric testing and thesample and bottle should be discarded. A second sample should be taken after at least 2 quarts ofsilicone fluid have been withdrawn. If separated water is still observed in the sample then refer toSection 6.2, Contamination.5-5 Dow 561 Silicone Tramformer LUquid Techmical Manual5.4 PumpingAlthough pmnps suitable for Dow Corning@ 561 Silicone Transformer Liquid are readilyavailable, not all pumps are suitable. Taking the care necessary to properly select a pump willensure good performance and long pump life.The two main considerations in selecting a proper pump for silicone transformer fluid arelubricity and seal compatibility. Information on lubricity can be found under Section 3.9,Lubricity. Information necessary to select proper seal and gasket materials can be found tunderSection 3.7, Material Compatibility.Pumps with metal-to-metal firiction requiring lubrication by the medium being pumped will eitherbe unacceptable in silicone or will result in excessive wear and short pump life. Gear pumps andhelical pumps are examples of this type. Pump suitability should be confirmed by the pumpmanufacturer. It is also possible to evaluate the pump's suitability by circulating a small quantityof silicone transformer fluid through the pump for an extended period of time and checking thepump for excessive wear.Table 5-i is a list of manufacturers that can provide pumps that are suitable for Dow Corning@561 Silicone Transformer Liquid. Consultation with the pump manufacturer is advised forselection of the best pump for your application. To properly size pumps, engineers should knowthat:" Dow Corning 561 Silicone Tranisformer Liquid is essentially Newtonian at all practical shearrates." Specific gravity, vapor pressure, coefficient of expansion, and viscosity-temperature relationshipinformation can be found in Section 3.8, Physical Characteristics.* Good engineering practice dictates the addition of a filter between a pump and a piece of electricalequipment. Other engineering considerations may include appropriate meters, valves, and otherrelief or control devices.Table 5-1. Pump manufacturersManufacturer Location Phone Types/specificationsGorman-Rupp Ind. BelIville, OH (419) 886-3001 Centrifugal, magnetic drive-specify 0-ringseat materialMarch Manufacturing Glenview, IL (847) 729-5300 Centrifugal-specify seal materialBlackmer Pump Co. Grand Rapids, MI (800) 759-4067 Rotary positive displacement-specify sealmaterialGoulds Pumps, Inc. Seneca Falls, NY (315) 568-2811 Centrifugal pumps-mechanical sealsViking Pump Division Cedar Falls. IA (319) 266-1741 Rotary gear pumps--specify silicone service5-6 Section 5: Material Handling5.5 Filling TransformersBefore putting a new transformer into service, verify that the transformer tank is free of moistureand any other foreign material.Procedures to be used for filling transformers with Dow Corning 561 Silicone TransformerLiquid do not differ significantly from methods used for filling transformers with mineral oil oraskarel. Although the following procedures are typical, they may not represent the only way orthe best way to fill transfornners with silicone fluid.Ifit is necessary to fill a transformer outside, particularly on a huifiid or rainy day, care should betaken to prevent moisture from entering the system. To avoid condensation, the temperatureinside the transformer should be kept several degrees above the outside air temperature. It ispreferable to prepare and fill outdoor apparatus on a clear, dry day.5.5.1 Filling under VacuumSince entrapped air is a potential problem in all fluid-filled transformers, it is desirable to filltransformers under vacuum. This is done for transformers shipped from the factory and, ifpractical, should be done when transformers are filled in the field. If the transformer case isdesigned to withstand full vacuum, an arrangement similar to that in Figure 5-2a can be used. Ifthe transformer case has not been designed for full vacuum and you must get the maximumwinding impulse strength immediately, the transformer should be filled with silicone transformerfluid under ftil vacuum by placing the entire transformer assembly in an auxiliary vacuum tank,as is shown in Figure 5-2b.If you don't have an established procedure for vacuum filling transformers, the followingprocedures can be used regardless of whether vacuum is applied directly to the transformer caseor the entire transformer is placed in an auxiliary vacuum tank.1. Apply and maintain a continuous vacuun of 50 toir for at least '/2 hour to units rated 25 kV orbelow, or for 4 hours to units rated above 25 kV.2. While holding vacuum, slowly fill the transformer with silicone transformer fluid to the normal250C level or, where it may be impossible to gauge properly, with about 90% of the requiredvolume.3. Maintain the specified vacuum for at least 1/2A hour after filling.4. Add sufficient silicone fluid to adjust the level to normal and seal the transformer tank. To avoidcondensation on the surface of the silicone transformer fluid, do not reopen the transformer untilthe temperature at the top of the fluid is equal to or higher than the ambient temperature.5.5.2 Filling without VacuumIn cases in which the transformer can not be filled under vacuum, full voltage should not beapplied to the windings for at least 24 hours after the silicone transformer fluid has been added tothe transformer case. This is necessary to allow air bubbles to escape.When practical, fill the transformer through the drain valve, as shown in Figure 5-2c, to miniimizeaeration, and vent the top of the transformer tank to allow air to escape. Be sure all valves andpipe connections between the main tank and any silicone-filled transformer compartments are5-7 Dow Corning 561 Silicone Transformer Liquid TechnicalA'anttalopen to allow free circulation of both gas and fluid. Otherwise, trapped air or gas could cause thesilicone-fluid level in some parts of the transformer to remain below the safe operating level.The transformer tank and compartments, if any, should be filled at ambient temperature to thepoint on the gauges marked "251C fluid level." If the ambient temperature varies greatly from25*C (771F) when filled, the level should be rechecked as soon as the average fluid temperatureequilibrates to the ambient temperature. Silicone transformer fluid should be added to or drainedfrom the tank to bring the level to the proper height. The transformer should never be operated orleft standing, even if out of service, without the proper silicone-fluid level indicated on the gauge.To vacuumsourcea. Filling wvith transformer caseunder racitiumr- ýDrum withheater Transformer(25-C to Wo-C)Lquid degasifierb. Filling with transformer caseplaced in a vacuum chamberTo vacuumsourceVacuum chamberand/or oven(1 to 5 torr)From drumor tankVentc. Filling from bottom whenracumn filling is not feasibleCartridge filter(I to 5p rn)From drumor tankTransformerFigure 5-2. Configurations forfilling transformers with fluid5-8 Section 3: Malerial Handling5.6 Vacuum DegasificationDielectric fluids should be filtered and degassed before being put into service in powertransformers. Ideal transformer fluids are low in impurities to maintain good dielectric properties;they also must maintain very low levels of dissolved air and water. A fluid with a dissolved-airlevel that is well below its saturation point will dissolve air bubbles trapped inside thetransformer insulation and eliminate those potential insulation system weak spots. Vacuumdegasifiers can reduce both water and dissolved-air content. The efficiency of water and airremoval depends on many factors such as:" Fluid temperature" Level of vacuum pulled* Initial water content of fluid" Fluid film thickness* Time of exposure to vacuum* The presence of boiling promoters (e.g., agitation, sharp points, rough surfaces, etc.)Effective removal of dissolved water by vacuum degasification requires specialized equipment.Table 5-2 is a list of manufacturers who can supply portable, semiportable, or permanent vacuum-degasification equipment.Refer to Section 3.8, Physical Characteristics, for information on vapor pressure, volumeexpansion, viscosity/temperatmne relationships, and gas solubility. This infornation may beimportant in specifying systems for silicone transformer fluid.Simply exposing transformer fluids to vacuum or spraying the transformer fluid through a nozzleinto a vacuum chamber or a transformer under vacuum. may not provide sufficient degasification.Spray degasification can be inefficient because under vacuum, in the absence of air or gas,dispersed fluid droplets tend to adopt a spherical shape that minimizes surface exposure. Unlessthe droplets are very small, the diffusion path for degasification is too long.For efficient degasification, a very thin film maximizes the transformer fluid's exposure tovacuum. The most efficient degasification processes use coliumls that spread the transformerfluid over a large surface area to create a thin film while the fluid is exposed to vacuum. Underthese conditions, the fluid degases readily. Degassing colunns may consist of more than onestage, with two-stage columns being quite common. The surface area of degassing columns isincreased by distributing the transformer fluid onto thin-walled steel rings or saddles that fill thecolumn. These materials, called column packings, are made in a variety of configurations such asRashig, Pall, or Norton rings or Berl and Kirschbaum saddles.To reduce viscosity during degassing, the transformer fluid can be heated. The appropriate temp-erature depends on the viscosity/temperature relationships and composition of the fluid in use.The purpose of vacuum filling a transformer tank is primarily to provide better impregnation byremoval of air from voids in the solid insulation. Degasification and drying of the transformerfluid is minimal. Consequently, transformer fluids should have acceptable dielectric propertiesbefore the fluid is used to fill the transformer.5-9 Dow CornInge 561 Silicone Transformer Liquid Technical ManualTable 5-2. Vacuum processing equipment manufacturersManufacturer Location TelephoneABVAC Inc. St. Louis, MO (800) 737-7937Pall Industrial Hydraulics Corporation East Hills, NY (800) THE-PALLSeaton Wilson, Div. of Systron Donner Corp. Sylmar, CA (818) 364-7204Baron USA Cookeville, TN (615) 528-8476Vacudyne Chicago Heights. IL (708) 757-5200Enervac Corporation (www.enervac.com) Cambridge, Ontario (519) 623-9890Kinney Vacuum Company Canton, MA (617) 828-9500This is not intended to be a complete list of manufacturers and suppliers of vacuum systems. Consultation with technicalrepresentatives or these manufacturers and suppliers is recommended to select the best system for your operation5-10 Section 5: Material Han ding5.7 Silicone Solutions for Mineral Oil FoamingContamination of mineral oil with some silicone fluids or other materials can cause severefoaming dinig processing. In severe cases, the foam is created in such large volumes that itprevents continued vactum processing of the transformer fluid. Laboratory studies indicate thatthis problem exists at levels as low as 100 ppm.The reverse problem-contamination of silicone transformer fluid by mineral oil causing foam-has not been observed. Instead, the problem with this type of contamination is a reduction of theflash and fire point of the silicone transformer fluid. See Section 6.2, Contamination, and Section3.10, Retrofill Considerations.The ideal situation is to avoid contaminating the transformer fluid in the first place and there arepractical ways to accomplish this. Contamination can be prevented by proper inventory controland by using equipment (pumps, hoses, etc.) that is dedicated exclusively to each fluid. In manyproduction facilities, spilled and unused transformer fluid that may accumulate along theproduction line is returned to a common storage tank. This practice can result in contaminatedfluid.If the same equipment must be used for both fluids, nonpolar solvents can be used to remove thesilicone transformer fluid firom equipment. However, you must replace filter media and cartridgeseach time you change fluids-even after solvent cleaning. The practice of sharing equipmentbetween two different transformer fluids is risky and is often unsuccessful because of incompleteremoval of the silicone fluid. Contamination of either transformer fluid with the solvent is also apotential problem.If a vacuum process results in a foaming condition, two antifoam materials have been proven toreduce the level of foam:* 12,500 cSt Don' Corning 200 fluid* 60,000 cSt Dow Corning 200 fluidWhen testing the effectiveness and practicality of Dow Coming silicone antifoams for industrialprocesses, an appropriate starting point is to add the antifoam to the foaming material at aconcentration of 50 ppm. The results obtained at this concentration will indicate whether toincrease or decrease the concentration of antifoam.In tests using prediluted antifoams, it is sometimes desirable to repeat the test using a differentdiluent. Depending on the type of material that is foaming, certain diluents can alter theperformance characteristics of the antifoam. Some diluents can enhance performance; others mayreduce it. For example, an antifoam formulation consisting of 95% (by weight) mineral oil and5% 60,000 cSt Don, Coring 200 fluid can be used to eliminate the foam. This formulationworks at concentrations as low as 0.2 ppm of the active antifoam in the transformer fluid.However, the formulation requires frequent agitation to maintain unifolmity. In contrast, adding12,500 cSt Dow Corning 200 fluid with no diluent to a foaming mineral oil system may requireas much as 50 ppm of the active ingredient.Similarly, an antifoam formulation consisting of 95% (by weight) mineral oil and 5% 60,000 cStDow Corning 200 fluid can also eliminate the foam at levels as low as 0.2 ppm. However, it toorequires frequent agitation to maintain uniformity.5-1i Dow Corning 561 Silicone Transformer Liquid Technical MannalFor an antifoam to work efficiently, it must be well dispersed in the fluid it is going to defoam. Itcannot just be dumped into the transformer-fluid storage tank. Figure 5-3 is a flow diagram of atypical vacuum degasification system. The ideal place to apply the antifoam is at a point upstreamfirom the filters, meters, valves, heaters, etc. The shear created by flow through these deviceshelps to disperse the antifoam. In addition, the antifoam may be partially retained on the filtermedium and be released into the fluid gradually. The antifoam addition port can be either a pointin the piping that can be opened or a fitting (e.g., a grease fitting) through which the antifoam canbe injected or purmped.StorageFigure 5-3. Block flow diagram of vacnun degasiJi'calion systein with location of antifoant injection port.Systems vary and it may be necessary to try several different-size antifoam injections to see howmuch fluid can be processed before the problem retuns. For a first injection, try 5 to 10 VL ofantifoam formulation. Comparing antifoam injection size with gallons of foam-free fluid willallow you to compute an ideal injection size and minimize the amount of antifoam used. Usually,smaller injections made more frequently will require far less antifoam formulation than largerinjections made at longer time intervals.The following equation should be helpffil in determining the amount of antifoam to add.(ppm antifoam) x (Anount of solution to be defoameda)Antifoam to be added [a-Mactive ingedient in antifoarb)x (10,000)Measure the amount ofantifoam added and solution to be defoamed in the same units: lb, gaL etc.bInert 10 for 10% actie, 30 for 30% actiw, etc.The conversion table below should be helpfuil in translating the calculated amounts to commonunits and determining the best way to add the required amount of antifoam.Table 5-3. Conversion tableHousehold measure Household measureParts per million Percent per 1000 lb per 1000 gal1 0.0001 -1 teaspoon10 0.001 1 teaspoon 8 teaspoons100 0.01 3 tablespoons 1-213 cups5-12 Section S: Material Handling5.8 Paint and PaintabilitySilicone transformer fluid will not protect unpainted surfaces from corrosion. If severe moisturecontamination occurs, corrosion could develop on unpainted surfaces. We recommend thattransformers and storage tanks be primed with a corrosion-inhibiting paint, such as a zinc-chromate alkyd. Any paint is compatible with silicone transformer fluid after proper paintapplication and drying. However, the paint application can be affected if the surface to be paintedhas been contaminated with silicone fluid, just as if the surface were contaminated with motor oil,grease, or perspiration.The best way to avoid application problems is to separate the areas where silicone fluid ishandled and where the painting is done. For silicone fluid to interfere with paint application, itmust get to the smuface. Since the vapor pressure of Dowv Corning 561 Silicone TransformerLiquid is very low, even at 100lC, vapor contact is unlikely to contaminate surfaces.Contamination usually occurs firom rags, hands, or other items that have been in contact withsilicone transformer fluid.There are two different techniques that can be used to paint surfaces that are known to becontaminated. One is to remove the silicone contamination as part of the surface preparationprocedures. The other is to use silicone paint additives to alter the wetting properties of the paint,making it compatible with the silicone contamination. Both are described in detail below.5.8.1 Surface PreparationAlthough removing silicone firom a contaminated surface may be somewhat more difficult thanremoving a conventional organic, and paintability problems may be encountered at lower levelswith silicone contamination, the differences are a matter of degree, rather than of kind. In mostcases, locating painting operations away from areas where silicone fluids are handled combinedwith routine smface preparation will prevent contamination. Should contamination occur,relatively simple cleanup procedures will render the surface paintable.An appropriate refinishing procedure might consist of the following steps:1. Wash the area to be repainted with a strong solution of automotive detergent in water. Manycommon household or industrial detergents are also satisfactory. Rinse the area thoroughlywith water.2. After the area has dried, wipe it down with a solvent such as turpentine, perohloroethylene, orxylene. Proprietary solvents (see Table 5-4) designed to remove silicones are also excellent-Disposable rags should be used so that the silicones will be removed and not redeposited.3. Apply masking tape, grind, and buff as necessary. For better paint adhesion, lightly sand allsurfaces to be repainted.4. Carefully remove all dust from the sanding and buffing operations. Again, wipe the surfaceclean with clean disposable rags soaked in solvent.5. Wipe the surface with a prepared tack rag to remove all dust and lint.6. Spray prime coat on any bare-metal surfaces and allow the primed surfaces to dry. Spray theentire area with the final paint or lacquer coats according to usual procedure.5-13 Dow Coming1, 561 Silicone Transformer Liquid Technical MannalTable 5-4. Proprietary solvents for removing silicone contaminationProduct Supplier Location TelephoneFish Eye Eliminator E.I. Du Pont de Nemours Refinish Sales Wilmington. DE (800) 441-7616No Fish Eye Liquid Glaze. Inc. Toccoa. GA (706) 886-6853Sila-Chek Additive V3 K 265 Sherwin-Williams Co. Chicago, IL (312) 278-7373Procedures were developed in 1950 for repainting silicone-polished automobiles. These -procedures involve washing with a strong detergent, followed by a solvent wipe. In order toprevent buildup of silicone in the solvent solution, disposable rags are recommended. These sameprocedures work well for the initial finishing of smfaces contaminated with silicone fluid and arerecommended for the cleanup of relatively small numbers of units where a short-termcontamination problem may exist. However, they would not be suitable for production-lineoperation.Other methods are suitable for surface preparation on a production-line basis. For example, thefeasibility of conventional vapor-degreasing techniques has been demonstrated. Standard paintpanels were deliberately contaminated, cleaned in a vapor degreaser with trichloroethylene, andfinished with both spray enamel and thermosetting acrylic powder.After successfully cleaning and repainting ten heavily contaminated panels, silicone fluid wasdeliberately added to the bath after each panel to accelerate the buildup of fluid in the degreaserand to simulate long-term use. Twenty panels were repainted- There was no contamination causedby the vapor at silicone fluid concentrations of I 1 parts of fluid in 7.51 parts of solvent.5. 8.2 Paint AdditivesSilicone transformer fluid itself may be used as a paint additive in solvent-borne paints. Onlyvery small levels are required; from 0.01% to 0.05% will do the job effectively. It is importantthat the 0.05% level not be exceeded to avoid altering other paint properties. Dow Corning paintadditives should be used to eliminate silicone-paint problems since these additives are speciallyformulated to provide even dispersion and improved flexibility.5-14 Section 6. MaintenanceSection 6: MaintenanceSection Content6.1 Periodic Inspection and Testing ....................................................................................... 6-16.1.1 V isual Inspection ................................................................................................... 6-26.1.2 Dielectric Strength (ASTM D877) ........................................................................ 6-26.1.3 W ater C ontent ........................................................................................................ 6-46.1.4 Gas Evolution/Arc Behavior .................................................................................. 6-46.2 C ontam ination .................................................................................................................. 6-76.2.1 Contamination with Water ..................................................................................... 6-76.2.2 Contamination with Particulates .......................................................................... 6-106.2.3 Contamination with Mineral Oil .......................................................................... 6-106.3 Filtration ..................... ................................................................................................... 6-116.3.1 Removal of Particulates ......................... ...... ................. 6-116.3.2 Filtration to Reduce Water Content .................................................................... 6-116.3.3 Filtration Equipm ent ............................................................................................ 6-126.4 L eaks .............................................................................................................................. 6- 136.5 Reuse, Recycle, or Disposal of Silicone Transformer Fluid .......................................... 6-146.5.1 R ecycling ............................................................................................................ 6- 146.5.2 Incineration and Landfill ..................................................................................... 6-156.5.3 Reprocessing and Disposal Services .................................................................... 6-156.6 IEEE Guide Availability ............................................................................................ 6-186.1 Periodic Inspection and TestingAlways follow the transformer manufacturer's recommendations for periodic inspection andtesting of the insulating (or dielectric) fluid. Dow Coining recommends that-at a minimnm-thefluid be sampled and tested after the first few days of operation, and the fluid level be checkedregularly thereafler. Periodic inspection and testing of the fluid is also recommended. Suchtesting can alert you to a performance or reliability problem before it results in transfonnerfailure. In fact, the ability to identify and correct problems before failure occurs is a significantadvantage of fluid-filled transformers.The inspection and testing frequency depends on the service to which the transformer issubjected. It is advisable to inspect silicone-filled transformers operating under extremely heavyloads more frequently than those in normal or light service. Referring to the station log and pasttest results should help identify an appropriate inspection and test frequency. The time betweeninspections should not be longer than one year, unless specific experience indicates that the timecan be extended.An appropriate test protocol is indicated in Table 6-1. Although acid number testing is included,this test does not reliably detect the degradation of silicones. The results could, however, suggestwhether contaminants are present.6-1 Dow Corning' 561 Silicone Transformer Liquid Tec/micalManualRefer to ASTM D2225 "Standard Methods of Testing Silicone Liquid for Use in Electrical Insul-ation" for further direction in testing silicone fluid. Visual inspection, dielectric strength, andwater content are discussed below in detail.Table 6.1. Recommended maintenance tests for silicone transformer fluidTest Reference Acceptable results Unacceptable results indicate...Minimum TestingVisual inspection ASTM D-2129 Crystal clear-free of Particulates, free water, colorparticles changeDielectric breakdown ASTM D-877 >35 kV for fresh liquid Particulates or water present>25 kV in transformerAdditional Recommended TestingWater content Modified Karl-Fisher, <100 ppm Excess water presentASTM D-1633Volume resistivity ASTM D-1169 >1 x 10i' Water or contamination presentDissipation factor ASTM D-1533 <0.2% Polar/ionic contaminationViscosity. ASTM D-445 50 h 2.5 cSt Degradation or contaminationFire point ASTM D-92 >340"C Contamination by combustiblematerialAcid number ASTM D-974 <0.2 Degradation of cellulose insulationor contamination6.L1i Visual InspectionDo;, Corning 561 Silicone Transformer Liquid is a water-clear, virtually odorless fluid.Because of the stability and chemical inertness of the fluid, no change in its appearance isexpected over the service life of the transformer.Any color change-such as to a green, red, or blue tint-could indicate extraction of impuritiesfirom the solid insulation. If a distinct color change is observed, check the complete range ofelectrical characteristics, as well as the flash and fire points, and notify the transformermanufacturer. The electrical characteristics may be unimpaired. Color change (except for white,gray, or black) is not necessarily a danger signal since the color contamination alone is unlikelyto impair dielectric strength.All samples taken for visual inspection should be obtained firom the bottom of the equipment.Particulates and water will settle to the bottom of silicone transformer fluid. When sampling, it isimportant that the procedures outlined in Section 5.3, Sampling, be followed closely. Ifparticulate material, gross discoloration, or free water is found during visual inspection, refer toSection 6.2, Contamination.6.1.2 Dielectric Strength (ASTMD877)Apparatus-The transformer and the source of energy must not be less than / kVA, and thefirequency must not exceed 100 Hz. The rate of voltage rise should approximate 3000 volts persecond. The voltage may be measured by any approved method that provides root-mean-square(rms) values.6-2 Section 6: MaintenanceThe test cup for holding the sample of silicone fluid should be made of a material having asuitable dielectric strength. It must be insohlble in and not attacked by silicone fluid or solventsand nonabsorbent with respect to moisture, silicone fluid, and solvents.The electrodes in the test cup between which the sample is tested should be square-edged circulardiscs of polished brass or copper, 1 inch in diameter. The electrodes should be mounted in the testcup with the axes horizontal and coincident, with a gap of 0.100 inch between their adjacentfaces, and with the tops of the electrodes about 11/4 inch below the top of the cup.Procedure-The spacing of electrodes should be checked with a standard round gauge having adiameter of 0.100 inch, and the electrodes then locked in position. The electrodes and the test cupshould be wiped clean with dry, calendered tissue paper or with a clean, dry chamois skin andthoroughly rinsed with Stoddard solvent (or another suitable solvent) until they are entirely freefrom fibers.The test cup should be filled with dr y toluene, and the voltage applied, increasing uniformly atthe rate of approximately 3000 volts (tins) per second until breakdown occurs. If the dielectricstrength is not less than 25 kV, the cup should be considered in suitable condition for testing thesilicone transformer fluid. If a lower test value is obtained, the cup should be cleaned withsolvent, and the test repeated. Observe the usual precautions in handling solvents.Evaporation of solvent from the electrodes may chill them sufficiently to cause moisture tocondense on their surface. After the final rising, heat the cell gently to evaporate the solvent andprevent moisture condensation. This can be accomplished with a heat gun.During testing the temperature of the test cup and the silicone fluid should be the same as that ofthe room-between 20 and 30'C (68 and 860F). Testing at lower temperatures may producemisleading or nonreproducible results. For routine testing, air temperature should be maintainedat 250C and the relative humidity at 50%.The sample in the container should be gently agitated with a swirling motion, to avoidintroducing air, so as to mix the silicone fluid thoroughly before filling the test cup. This is evenmore important with used silicone fluid than with fresh, since impurities may settle to the bottom.The cup should be filled with silicone transformer fluid to a height of no less than 0.79 inches (20mm) above the top of the electrodes.The silicone fluid sample should be gently agitated again by rocking the cup and allowing it tostand in the cup for 3 minutes before testing. This will allow air bubbles to escape.Voltages should be applied and increased uniformly at a rate of approximately 3000 volts (mis)per second until breakdown occurs, as indicated by a continuous discharge across the gap.(Occasional momentary discharges that do not result in a permanent arc should be disregarded.)Tests--Only one breakdown test may be made per cup filling. After each breakdown test, the testcup should be drained and the electrodes should be wiped clean with a lint-free disposable tissueto remove any arc decomposition products, which tend to adhere to the electrodes.One breakdown test should be made on each of five successive fillings of the test cup. Computethe range of the five breakdown tests (maximum breakdown voltage minus minimum breakdownvoltage) and multiply this range by 3. If the value so obtained is greater than the next-to-the-lowest breakdown voltage, it is probable that the standard deviation of the five breakdown tests isexcessive and the probability error of their average is also excessive.6-3 Dow Corning 561 Silicone Transformer Liquid TecinicalManualIf the five values meet the criteria above, the average value should be reported as the dielectricbreakdown voltage. If they do not meet the criteria, one breakdown test on each of five additionalcup fillings should be made and the average value firom all ten breakdown tests should bereported as the dielectric breakdown voltage of the sample. No breakdown test should bediscarded. When the dielectric breakdown voltage of a fluid is to be determined on a routinebasis, one breakdown test may be made on each of two fillings of the test cup. If no value isbelow the specified acceptance value, the fluid may be considered satisfactory, and no furthertests should be required. If either of the values is less than the specified value, a breakdown testshould be performed on each of three additional cup fillings, and the test results analyzed asdescribed above.6.1.3 Water ContentASTM D2225 "Standard Methods of Testing Silicone Liquids Used for Electrical Insulation"specifies that water content should be determined in accordance with ASTM D1533, except that a1:1 blend by volume of dry formamide and dry methanol is used instead of thechloroform/methanol solvent. This is known as the modified Karl-Fisher method. Silicone fluidscan contain silanols or OH groups on the polymer chain. These silanols can react with normalKarl-Fisher reagent to generate water, resulting in a high reading. The modified Karl-Fishermethod eliminates much of the problem.A titration method also recognized by ASTM (and preferred by Dow Coming) is an automaticKarl-Fisher titrator, such as the Aquatest IV by Photovolt. Automatic titrators tend to reduceinterference problems even further. In fact, the Aquatest IV has been very effective in accuratelymeasuring the water content ofDost Corning 561 Silicone Transformer Liquid to within 10ppm.6-1.4 Gas Evolution/Arc BehaviorEvolution of Gases in Partial Discharge Tests-The absolute amount of gas that is generated inpartial discharge tests is related to the specific test that is conducted. The linear relationshipshown in Figure 6-1 indicates that chemical changes in the silicone transformer fluid subjected topartial discharges depends on the electrical energy delivered to the discharge site.Gas Evolution Due to Arcing Between Electrodes-Previous studies have demonstrated that itis difficult to sustain an arc in silicone sotransformer fluid at low current levels. Thebreakdown of the silicone transformer fluidresults in instant formation of solids between 6 oru O/0)the two fixed electrodes. A "bridge,"consisting of silica and carbon held together 2 40by gelled fluid, forms across the electrode 2O20gap. The characteristics of this bridge are 20 20directly dependent on the initial energy inputof the first arc current. The arc is generally 0extinguished and the generation of gas is 0.01 0.10 1.00reduced or eliminated completely. Amunt of nartisl disha- -Figure 6-1. Erohled gas volume under partialdischarge conditions6-4 Section 6: Maintenance150-jEC9C,a-JSj'02502001501Section 6: tllaintenanc¢-0- Silicone_0_7Mi7neral oil100!500 v0.00I ....I I I I1.0 2.0 3.0 4.0 0 50 100 150 200 250Arc energy. kWsFigure 6-2. Evolved gas rohlme due to arcing atmoderate current levels for Dow Corningt561Arc energy, kW sFigure 6-3. Evolved gas rolume due to airing athsigh current levelsfor Dow Corning 561Under arcing conditions with moderate (Figure 6-2) and high (Figure 6-3) currents, the volume ofevolved gases in silicone transformer fluid is similar to that evolved by mineral oil. These dataindicate that the principles used to design transformer tanks for mineral-oil service can be appliedto transformer tanks for silicone fluid.As reported in Table 6-2, analysis of the decomposition gases from low-current arcing in siliconetransformer fluid showed hydrogen, IL, to be the main component. However, substantial amountsof carbon monoxide, CO, were also evolved. Comparison tests showed that with mineral oilconsiderable acetylene, C2H2, is evolved in addition to H,.Table 6-2. Typical analysis of gas evolved in arc conditions with Dow Corning 561 and mineral oilDow Corning, 561 Mineral ellCurrent 810 mA 715 mA 26.2 A 345 mA 1050 mA 15.9 AElectrode Rotating @ Rotating @ Fixed Rotating § Rotating @ Fixed24 rpm 120 rpm 24 rpm 120 rpmAnalysis, volume percentH2 74.6 75.6 77.1 65.0 68.3 73.4CO 19.0 17.2 14.0 ---CH4 1.7 1.2 4.0 1.2 2.0 3.5C2H2 4.3 6.7 3.8 32.8 26.6 20.7C2H4 0.4 0.3 1.1 0.8 1.4 2.1C2H8 trace trace -trace trace 0.03C3He trace --0.2 0.2 0.2C3H8 ---trace trace traceEvolved gas, mL/kW-sMeasured 22 35 3 45 45 48Calculated a8 89 82 65 57 47Interpretation of Dissolved Gases in Silicone Transformer Fluid-For many years gas-in-oilanalysis has been used to diagnose the condition of oil-filled transformers. The industry hasattempted to apply this tool to silicone-filled transformers. Although the primary gases evolvedunder fault conditions in silicone fluid are similar to those evolved in mineral oil, the relative6-5 Dow Corningg 561 Silicone Transformer Liquid TechnicalMarnalproportions of those gases differ. Standard procedures have been established for fluid sampling,analysis, and interpretation of gas-in-oil.At present, the IEEE Insulating Fluids Subcommittee is developing a guide for the interpretationof gases generated in silicone-immersed transformers. More information on the development andinterpretation of dissolved gases is available by requesting item PIO listed in Section 1.5,Bibliographic Resources.There is also increasing interest in applying furan analysis techniques to detect degradationwithin transformers. This approach can be helpful in determining whether cellulosic insulationmaterials are being degraded, especially when the data are interpreted in combination with gasanalysis data. However, since the technique is relatively new, not all testing services offer thistype of analysis, and it is especially important to select an experienced testing organization toperform the analysis.6-6 Section 6: Mahitenance6.2 ContaminationFluid contamination can occur in many ways. To ensure that Dow Corning 561 SiliconeTransformer Liquid performs properly, it should be maintained in as clean and pure a state aspossible. Even if contamination does occur, recovery of contaminated fluid is often possible.Table 6-3 is a summary of the information discussed in detail in the sections that follow.Table 6-3. Summary of common contamination problems and corrective actionLiquid CorrectiveContamination appearance Oetection testing action Suggested filter CommentsmediaWater Clear to milky Dielectric strength or modified Vacuum Free water should bewhite Karl-Fisher titration, preferably degasificafion siphoned, decanted or drainedwith automatic titrator before processing the fluidFilter press Paper or absorbent,e.g., diatomaceousearthCartridge lilter Absorbent cartridgesParticulates Clear with Dielectric strength Cartridge liter None or datomaceousvisible or filter press earth as filter aidparticles, hazyMineral cit Clear or twc- Flash and Pre point or None None No economical methods existphase, mineral specialized testing for removing mineral oil fromoil odor silicone fluid6.2.1 Contamination with WaterIn most practical applications involving the handling of transformer fluids, the rate of waterabsorption and dissipation is very important. In practice, however, the determination of moisturepick-up rates is very difficult since the rate is dependent upon the equipment configuration. Thesize, shape, and area of contact between the fluid and its environment affects the rate at which thefluid approaches its equilibrium water content. In certain test configurations, the rate of waterabsorption of silicone transformer fluid was similar to askarel.When opening a transformer in a humid-air environment, exposure time should be limited tominimize transport of water vapor into the fluid. The same guidelines that have been establishedfor askarel-filled transformers are recommended.Within most fluid-filled transformer configurations there is an extremely large solid-to-liquidinterface. The cellulose-based materials commonly used as transformer insulation are veryhygroscopic and can absorb almost as much water as silica gel. Any water dissolved in theinsulation system will reach a steady-state equilibrium with the transformer fluid, with most ofthe water remaining in the insulation. Thus, dry cellulose immersed in wet transformer fluid willdehydrate the fluid, with most of the moisture absorbed by the cellulose. The reverse process isalso tree in that dry fluid will absorb water from wet cellulose insulation. Evaluating the watercontent of the system based on a single measurement of the fluid water content may bemeaningless.Silicone fluids behave similarly to mineral oils and askarels with respect to transport of moistureinto the transformer insulation. However, the saturation and equilibrium condition of silicone6-7 Dow Corning& 561 Silicone Transformer Liquid Technical Mantalfluids with insulation may be quite different from the other fluids. It is often more meaningful toconsider the steady-state water content of the system than the water content of the fluid alone.Experience in processing and manufacture of silicone fluid and silicone-fluid-filled transformershas shown that water can be removed from silicone fluid using conventional vacunm-dryingtechniques. Large manufacturers of silicone-fluid-filled transformers use the same vacuum-temperature treatment of dry and fluid-saturated windings as those that have been established formineral-oil-filled and askarel-filled transformers. Smaller manufacturers have found that ovendrying the windings and applying vacuum to the tank after assembly will produce a transformerwith excellent dielectric properties.A procedure that applies a vacuum of I to 2 ton at 105.C for 18 to 24 hours can be used toaccelerate the transport of moisture from the inner layers of the coil to the air interface andpromote release of the moisture to the air. Higher temperatures may accelerate the drhying time;however, the 105'C temperature minimizes thermal degradation of the cellulose and keeps thecost of the vacuum system relatively low. When repairing a winding that is akeady saturated, thedrying period should be extended to 48 hours to compensate for the reduced diffusion anddissipation rates of the water. If field repairs are necessary and a vacumn system is not available,a 48-hour drying time is recommended.Refer to Section 6.3, Filtration, for information on removing water from silicone transformer fluidusing filtration. Refer to Section 5.6, Vacuum Degasification, for additional information onremoving water by vacuum treatment.Effect of Water Contamination-Figure 6-4 250 _shows that water is soluble to some extent in all E 2 M oSv scommon transformer fluids. Silicone fluid has a 2W B Shigher saturation water content than either fresh --askarel or mineral oil. This is significantbecause, as shown in Figures 6-5 and 6-6, some o100dielectric properties deteriorate rapidly in the "presence of moisture. Despite its higher water / 50content at saturation, silicone transformer fluidmaintains good dielectric properties at much 0 , , ,higher water levels than askarel or mineral oil. Silicone Askarel Mineral oilFigure 6-4. Sohtbilirl, of water in variousDissipation factor and dielectric constant are not transfornerflidsaffected by the water content of the fluid alone.However, the dissipation factor of silicone-impregnated paper is affected by water. Volumeresistivity will decrease linearly with water content in much the same way as dielectricbreakdown. The relationship between volume resistivity and water content is shown in Figure 6-7. The partial discharge characteristics will also change with water content as shown in Figure 3-14.6-8 Section 6. Maintenance100 100Si-si,-M .2 @ 25°s o -w l o -1 c 50 >.t"0 10 t.".$2 00*. b 4 0* U,.O l200 50 100 150 200 250 300 0 50 1 00 150 200Water content, ppm Water content, ppmFigure 6-5. Decrease in dielectric strength with Figure 6-6. Breakdotwn voltage changes withwater content for Dow Cornng 561 water contentfor transformer flnids-12.5min diameter sphere-to-sphere electrodeswith 2.5 mm gapRates of Water Pickup and Removal-Figure 6-8 shows the rate at which mineral oil andaskarel pick up water when exposed to air of different humidities. In this work the fluids wereexposed in a quiescent state under the following conditions:Volume of fluid 7,500 cm'Smrface area exposed 375 cmaFluid depth 20 cmTemperature 25 OCFigure 6-8 shows that the sorptive ability of the fluid varies considerably. Askarel fluids pick upwater more rapidly than mineral oil. A similar test on silicone transforner fluid (Figure 6-9) isalso shown. The data cannot be compared directly to the mineral-oil and askarel data since thefluid volume is smaller and the surface areaV100 --Uwtoý2 120~2E 1000oC51 40% PHE20 259%6 RH0> 0.1 t i i ,> 0 ,'0 10O0 150 200 250 0 .......a 20 40 60 80 100Water content, ppm "Time, hoursFigure 6- 7. Relationshif of tolume resistivity of Figure 6-8. Rate ofirater absorption for trans-Dow Cornhig" 561 to wvater content (15- fonner fluids at varions relatfiverain stress data, Keithle, 610R)htidtehimdii86-9 Dow Corning 561 Silicone Transforiner Liquid TechnicalMamialto fluid depth ratio is much larger than in the tests above. The faster water pickup may be a resultof these geometrical differences- However, if a linear relationship between sample dimensionsand the time to reach equilibrium is assumed, the hygroscopic behavior of the siliconetransformer fluid appears to be similar to askarel fluids.Figure 6-9 also shows how rapidly water can be removed firom the silicone fluid under milddrying conditions at 450C. Experience with silicone transformer fluid during processing andmanufacture has shown that silicone fluid can be dried to a low water content using eitherconventional or vacuum ovens. In the U.S., all large manufacturers of silicone-filled transformersuse the same vacuum-temperature treatment of dry windings and fluid-saturated windings that hasbeen established for mineral oil and askarel fluids. Practical work has suggested that drying ofsilicone fluid is best canied out in a conventional degasifier operating with vacuums of I to 2 tortand at temperatures between 20 and 80°C. Typical flow rates used in these degasifiers are 15 to30 liters per minute.The equilibrium moisture balance between humid air and Dow Corning 561 SiliconeTransformer Liquid depends on the humidity of the air and the water content of the fluid. Dry airwill tend to dry wet fluid and wet air will add moisture to dry fluid. The rates at which thishappens depend on such factors as surface area of fluid exposed to air, agitation, temperature, andthe relative difference in the vapor pressures. A graph of the equilibrium water content of siliconetransformer fluid at various relative humidities is shown in Figure 6-10.200 200175 Begin Dojing E175 .E150 al150HO ai.125 @V 100 75RH1083~375so0 .. 50 025 3:__ __ _ _ _0 _______________ 00 20 40 60 80 100 120 0 20 40 60 80 100Time, hours Relative humidity, percentFigure 6-9. Water absoiption and drying curves Figure 6-10. Equilibrium betwveen moisture in airfor Dow Corning 561 and water content of Dow Cornming 5616.2.2 Contamination with ParticulatesRefer to Section 6.3, Filtration, for removal of particulates.6.2.3 Contamination with Mineral OilThe solubility/miscibility of mineral oil in Dow Corning 561 Silicone Transformer Liquid canvary with temperature and the feedstock composition and purification methods used to producethe mineral oil. Mineral-oil contamination will reduce the flash and fire points of Dow Corning561 Silicone Transformer Liquid (See Table 3-26). Refer to Section 6.5 for information andoptions for removing contaminants-including mineral oil-firom silicone fluid.6-10 Section 6: Maintenance6.3 FiltrationSilicone transformer fluids can be filtered to:* Remove particulate (solid) contamination* Reduce water content6.3.1 Removal of ParticulatesThe type, amount, and size of the particles to be removed are important to the effectiveness ofvarious methods of filtration. Three basic filtration devices are available: cartridge, filter press,and bag. The cartridge filter is usually the most effective and convenient. Cartridges haveabsolute filtration ratings. The rating, expressed in microns (micrometers, pm), is equivalent tothe largest particle that can be passed. Absolute ratings of five microns or less will generally besufficient to filter dielectric fluids for power transformers.A limiting factor in the use of cartridge filters is the amount of particulate material that can beremoved before the cartridges fill and begin to plug off. If large amounts of particulates arepresent, a filter press may be more effective. An example might be where adsorptive filter aidshave been added to the dielectric fluid to aid in purification.Bag filters can remove larger volumes of particulates. However, a 3-micron nominal rating for abag filter, for example, compares more closely to a 15-micron absolute rating. Bag filters aremore appropriate for crude filtration that is followed by a secondary filtration step with a finerfilter element.6.3.2 Filtratdon to Reduce Water ContentFor a discussion on the effect of water on the properties of Dow Corning 561 SiliconeTransformer Liquid, see Section 6.2, Contamination.Water is largely insoluble in silicone transformer fluid. Free, or undissolved, water will separatefrom the fluid and settle to the bottom of the container. Silicone transformer fluid will appearmilky white if contaminated with dispersed free water. The silicone fluid should not be used ifthis condition occurs. As much as possible of the dispersed free water should be removed byallowing the suspension to break and settle. Placing the container in a cool, dry area mayfacilitate this. Free water can then be removed by siphoning, draining from the bottom, orcarefilly decanting. However, the fluid must be further dried to remove any dissolved water.It is difficult to remove large amounts of free water by filtration. Rapid wetting and saturation ofthe filter medium occurs, and excess water becomes dispersed in the fluid. However, traceamounts of dissolved water can often be removed with filtration techniques. This process is nottrue filtration; rather, the dissolved water is adsorbed onto the hydrophilic filter medium.Dissolved water is not visible and must be detected by dielectric measurements or by otherappropriate analytical techniques. (See Section 6.1, Periodic Inspection and Testing.)A common approach to removal of water in transformer fluids is to use a blotter press. Care mustbe taken to properly dry any filter media to be used in the operation. Filter paper or cartridgesshould be dried immediately before use. For good results, spread the paper for maximum surface6-11 Don Co'nlngt 561 Silicone Transformer Liquid Technical Manualexposure in a hot-air circulating oven for 4 to 6 hours at 11 0°C. Even better results can beobtained by drying the filter medium in a heated vacuum oven at 110°C for 4 to 6 hours.An alternative to the filtration approach is to use a molecular-sieve bed to remove trace amountsof water. Molecular sieves can remove dissolved water from silicone fluid effectively andeconomically. Molecular sieves with a 10 to 13 A pore size are recommended for water removalfrom silicone fluid. However, the most effective method of water removal is by vacuumdegasification as described in Section 5.6.6.3.3 Filtration EquipmentTable 6-5 is a list of companies that supply filtration equipment. It is strongly recommended thatall apparatus used in sampling, filtering, storing, or transporting silicone transformer fluid bemaintained for exclusive use with silicone fluid.It is extremely difficult to remove all traces of hydrocarbon oil or other contaminants firomequipment of this type. In addition, care must be taken to protect all such equipment from theelements and from water or moistmue contamination.Table 6-5. Filter equipment manufacturersManufacturer Location Telephone Types of equipmentFilterlte DIv. of Merntec America Timonlum. MD (410) 560-3000 Filtertubes and housingsFilter Specialists Inc. Michigan City, IN (800) 879-3307 Bag filters, pressure vessel filter housingsSethco Division Hauppauge, NY (516) 435-0530 Cartridge filtersPall Corporation East Hills. NY (800) THE-PALL Cartridge filters, filter housingsCarborundum Corp. Various In U.S. Cartridge filters, filter housingsShutte & Koerting Bensalem, PA (215) 639-0900 Cartridge filters, filter housingsAlsop Engineering Corp. Kingston, NY (914) 338-0466 Cartridge filters for the electrical IndustryFiltration Systems Div. St. Louis, MO (800) 444-4720 Filter pressesAquaCare Systems. Inc. Angola, NY (716) 549-2500 Filter pressesPatterson Industries Scarborough, ON (800) 336-1110 Filter pressesThis is not intended to be a complete list of filter-equipment suppliers. Not all equipment supplied by these companies may besuitable for Dow Corninge! 561 Silicone Transformer Liquid. Consultation with the equipment manufacturer is recommended.6-12 Section 6: Maoitenance6.4 LeaksLeaks may occur during the lifetime of a silicone-filled transformer. As part of any regularmaintenance schedule, routine checks should be made to detect leaks. Areas to check and repairshould include valves, bushings, gauges, tap changers, welds, sample ports, manhole covers, pipefittings, pressure-relief valves, etc. In short, the entire surface of the tank and all devicesconnected to it should be inspected for leaks.If the leak is at a gasket surface, the leak can be repaired by either installing new gaskets or, if thegasket is still serviceable, tightening down the burrs or bolts provided for that purpose.If the leak does not involve a replaceable seal or simple retightening, welding and epoxy sealingkits are two conunonly used techniques to repair the leak.Silicone transformer fluid is an effective release agent; it prevents the formation of adhesive orcohesive bonds. As a result, most epoxy sealing kits used to patch mineral-oil or askarel leakswill not work on leaks involving silicone fluid. Proper surface preparation is difficudt unless thesilicone-fluid level is lowered below the leak. If the sealing kit is applied and fully cured beforerefilling the transformer to the normal fluid level, the seal will remain in place and stop the leak.Repair bonds formed before contacting silicone or bonds made on surfaces prepared inaccordance with Section 5.8, Paint and Paintability, are unaffected when exposed to siliconefluid.If leak repair requires reducing the fluid level, proper care must be taken to protect the purity ofthe silicone transformer fluid. Dedicated equipment and clean, dry storage containers must beused. Testing of the fluid is necessary before returning the transformer to its normal fluid level.All sampling, testing, and filling of transformers should be in strict accordance with therecoinnendations presented in this manualA more recent development is a sealing kit specifically designed for sealing leaks in silicone-filled transformers. For more information on this kit, contact:Lake Chemical250 North Washtenaw Ave.Chicago, Illinois 60612(312-826-1700)Ask for information on Epoxy Tab Type S.6-13 Dow Cormtgni 561 Silicone Transformer IAqtdd Teclnica Afannal6.5 Reuse, Recycle, or Disposal of Silicone Transformer FluidDow Corning's commitment to the environment is demonstrated by its willingness to assistcustomers in understanding options for handling used and/or contaminated Dow Coring 561Silicone Transformer Liquid. One of the strongest value points and least understood benefits ofsilicone fluid is the variety of options available to customers at end-of-use. Dow Corning firmlybelieves that waste minimization and reuse or recycle are much preferred alternatives to productdisposal.For transformer manufacturers, service companies, and large utility customers, wasteminimization can take many forms. These include:* Purchasing the proper quantity of material to reduce excess* Minimizing the length of transfer piping that may require cleaning* Reviewing systems to ensure secure storage, transfer, and usage* Protecting equipment against physical damageIn 1996 Dow Corning established the Dow Corning 561 Silicone Transformer LiquidRegistration and Recycling Program as a multibenefit option for fluid nearing its end-of-use pointor fluid contaminated with water, particulate matter, or mineral oil. The program is intended toreduce end-of-use handling concerns for prospective customers while at the same time providing100% closed-loop life cycle for the fluid. Registration ensures that a transformer purchased today(or purchased in the past) containing Dow Corning@ 561 Silicone Transformer Liquid will be acandidate for recycle consideration at end-of-use. More information on this program is availablein a separate literature piece from Dow Coming (Literature No. 10-710-96).6.5.1 RecyclingRecycling options include:* Reusing the material in the same application* Reprocessing of fluid contaminated with water, particulates, or mineral oil* Special reprocessing of fluids contaminated with PCBs" Fuel blending to recover energyIn some cases, fluid can be reused in the same application without reconditioning. DowCorning" 561 Silicone Transformer Liquid can also be reprocessed to remove contaminants andthen reused in transformers in many cases.Commonwealth Edison, a major Illinois utility, has a reprocessing system in place specificallydesigned for recycling silicone transformer fluids. Commonwealth Edison specializes in fluidscontaminated with water and/or particulates.Silicone transformer fluid can also be reprocessed by the transforner owner or by a reputableservice company. Reprocessing procedures are discussed in Sections 5.6 and 6.3 as well as inIEEE C57.111.Dow Coining's Registration and Recycling Program is designed to accept fluids contaminatedwith water or particulates and that also meet certain other recycling criteria. Additionally, the6-14 Section 6: Mainten anceDow Coming program can reprocess fluid that has been contaminated with mineral oil. Thiscontamination may have resulted from several scenarios, but the most common one occurs whentransformers originally filled with mineral oil are retrofilled with silicone fluid to improve firesafety and reduce long-term maintenance. Silicone fluid used to flush the mineral oil transformeris also a candidate for the Dow Coming program. Until this program began in 1996, the primarymethod for recycling this type of contaminated fluid was fuel blending or incineration.Material returned to Dow Coming as part of the Registration and Recycling Program is returnedone-way. Returned fluid is completely restnrctured through chemical reprocessing and then usedto rebuild other specific silicone products. The Dow Coming program cannot, under anycircumstances, accept fluid contaminated with PCBs.SunOhio specializes in PCB-contaminated materials and is an option for those transformers thatmay contain PCB-contaminated fluids resulting from prior use of PCB fluids.Fuel blending is another recycling alternative. Most non-PCB-contaminated silicone fluids areconsidered nonhazardous waste when disposed and can be compatibly blended with many organicsolvents or other fuels. However, oxidizers and other incompatible materials as spelled out in thematerial safety data sheets should not be blended with silicones.Silicones have two advantages when properly used in fuel-blending operations. Silicone fluidshave a fuiel value of approximately 8,000 Btu per pound, providing a favorable heat balance forfuel-use applications. Further, when silicone fluids are binned in silica-demanding processes suchas cement kilns, the resulting silica becomes a valuable component of the product.Silicone-containing materials should not be burned in internal combustion engines or otheroperations in which ash generation may interfere with the operation of the equipment. Alwayscheck equipment specifications and/or local regulations as appropriate prior to combustingsilicone materials.6.5.2 Incineration and LandfillIf other reuse and recycle methods have been thoroughly investigated, and destruction is the onlyremaining alternative, incineration of Dow Corning 561 Silicone Transformer Liquid can beconsidered. As with fuel blending and other combustion activities, incineration must consider theheat content of silicones and the silica ash generated by the combustion process.Absorbents or other solid materials contaminated with Dow Corning 561 Silicone TransformerLiquid that might have been generated duning maintenance or clean up of minor leaks or spills(assuming no PCB contamination is present) can be landfilled if local regulations allow.6.5.3 Reprocessing and Disposal ServicesTable 6-6 provides an overview of the alternatives and qualified reprocessors and disposalservices. The lists on the following pages provide names, addresses, telephone munbers, anduniform resource locators (URL) on the World Wide Web for those companies. For furtherinformation on recycle or disposal of Dow Corning 561 Silicone Transformer Liquid or otherDow Corning silicone products, contact your Dow Coming representative, or call (800) HELP-561 (in Canada, call (416) 826-9600).6-15 Dow Corning* 561 Silicone Transfornmer Liquid Technical ManualTable 6-6. Reuse, recycle, and disposal alternatives for Dow Cornlng@ 561 Silicone Transformer LiquidFluid without PCB contamination Fluid with PCB contaminationReprocessing toremove water or Reprocessing to Reprocessing to ServicesUsed but not particulate remove mineral remove PCB orcontaminated contamination oil contamination Fuel blending contamination incinerationCustomer %/Commonwealth Edison /S.D. Myers V VDow Coming 1' VPhillips Environmental VSystech Environmental "Safety-Kieen Corp. VSunOhio, Inc. vIncinerators /Reprocessing of Dow Corninhg 561 Silicone Transformer Liquid contaminated with waterand/or particulates (not PCBs) may be obtained firom:Commonwealth Edison1319 South First AvenueMaywood, IL 60153(708) 410-5476S.D. Myers180 South AvenueTallmadge, OH 44278(330) 630-7000Web site: http://www.sdmyers.comDow Corning CorporationMidland, Michigan 48686-0994(800) HELP-561Reprocessing of Dow Coning 561 Silicone Transformer Liqiuid contaminated with mieral'oilis available through Dow Corning's Registration and Recycling Program:Dow Corning CorporationMidland, Michigan 48686-0994(800) HELP-561Reprocessing Dow Corning 561 Silicone Transformer Liquid contaminated with PCBs may beobtained from:SunOhio1515 Bank Place, S.W.Canton, Ohio(888) suNomoWeb site: http://www.slmohio.com6-16 Section 6: MaintenanceRemoval and disposal of Dow Corning 561 Silicone Transformer Liquid contaminated withPCBs is available from:S.D. Myers180 South AvenueTallmadge, OH 44278(330) 630-7000Web site: http://wxvw.sdmyers.comThe following companies offer waste fiel-blending services for energy recovery:Phillips Environmental515 LycasteDetroit, Ivl 48214(313) 824-5850Systech Environmental245 North Valley RoadXenia, OH 45385-9354(800) 333-8011Safety-Kleen Corporation1000 North Randall RoadElgin, IL 60123(800) 669-5740Web site: http://www.safety-dleen.com/6-17 Dow Cornlngt 561 Silicone Transformer liquid Technical Manual6.6 IEEE Guide AvailabilityThe comprehensive IEEE Guide for Acceptance of Silicone Insulating Fluid and Its Maintenancein Transformers (IEEE C57.111-1989) can be obtained by writing:Institute of Electrical and Electronics Engineers, Inc.345 East 47th SkeetNew York, NY 10017U.S.A.6-18 LIMITED WARRANTY INFORMATION -PLEASE READCAREFULLYThe information contained herein is offered in good faith and isbelieved to be accurate. However, because conditions and methods ofuse of our products are beyond our control, this information shouldnot be used in substitution for customer's tests to ensure that DowComing's products arc safe, effective. and fully satisfactory for theintended end use. Suggestions of use shall not be taken asinducements to infringe any patent.Dow Coming's sole warranty is that the product will meet the DowComing sales specifications in effect at the time of shipment.Your exclusive remedy for breach of such warranty is limited torefund of purchase price or replacement of any product shown to beother than as warranted.DOW CORNING SPECIFICALLY DISCLAIMS ANY OTHEREXPRESS OR L-IPLIED WARRA-NTY OF FITNESS FOR APARTICULAR PURPOSE OR MERCHAINTABILUIY.DOW CORNING DISCLAIMS L[ABJJJTY FOR ANYINCIDENTA4.L OR CONSEQUENfTAL DAMAGES.Dow, Corning is a registered trademark of Dow Coming Corporation.Printed in USA. Form No. 10-453A-01Dow Coming CorporationMidland, Michigan 48686-0994FDOIV CORNING I ATTACHMENT 5Fire Protection Program Audit FrequencyMaterial/Documentation to support the current frequency of the audits based on the results of past audits.Audit/ Assessment Date Comments Quotes from Report on FrequencyNumberSSA0101 Fire 5/03/2001 Last annual FleetProtection and Loss Audit prior NQAPPrevention Program Frequency RevisionSSA0201 Fire 4/18/2002 SQN Only Regulatory Guide 1.189, "Fire Protection for Operating Nuclear PowerProtection and Loss Plants," allowed WVAN to change annual audit intervals to a "maximumPrevention.pdf interval of 24 months" by implementation of a performance-based schedulejustified by performance reviews) provided the maximum audit intervaldoes not exceed the two-year interval specified in ANSI N18.7. NAreviewed all three sites' performance and concluded that BFN and WBNFire Protection Programs indicate last year's performance justified going toan interval of 24 months and that this audit would be conducted for SQN.SSA0301 Fire 3/21/2003 WBN, SQN, BFN This report documents the first Fire Protection audit performed sinceProtection and Loss attributes of the annual, biennial, and triennial audit were combined into aPrevention Program single audit. The audit identified 1 significant audit issue at SQN and 46Audit (Biennial/Triennial) other problems (9 at BFN, 15 at WBN, and 22 at SQN). These issues wereentered into each site's Corrective Action Program.SSA0501 -Fire 6/01/2005 WBN, SQN, BFN 1) CORP PER 76142, Level C; The following problems were identifiedProtection And Loss during preparation for the upcoming Fire Protection Program Audit,Prevention Program SSA0501.Audit (Biennial/Triennial) 1. The CY 2005 Fire Protection Audit was not started in time to meet thefrequency required by the NQA Plan.2. An evaluation of the fire protection program was not performed by NA inlate 2003 as required by NADP-2, Audits.3. Neither the NQA Plan nor NADP-2 identifies Regulatory Guide 1.189 asthe commitment document for Fire Protection Audit frequencies.NA-CH-06-003 3/31/2006 WBN, SQN, BFN There was satisfactory management oversight of system healthAssessment Of Valley- performance which allows NA continued biennial frequency for audits.Wide Fire Protection There was one recommendation for program enhancements forPerformance considerationSSA0605 FIRE 4/27/2007 WBN, SQN, BFN Dates of Audit were December 11, 2006 through March 21, 2007PROTECTION AND Observation 41937 at WBN discussed the change in audit frequency, butLOSS PREVENTION this was not part of the formal report.PROGRAMPage 1 of 2 ATTACHMENT 5Fire Protection Program Audit FrequencyMaterial/Documentation to support the current frequency of the audits based on the results of past audits.Audit/ Assessment Date Comments Quotes from Report on FrequencyNumberNA-CH-07-004 -Nuclear 1/08/2008 WBN, SQN, BFN The Fire Protection (FP) program assessment was performed to fulfill thePower Group (NPG) requirement of NADP-2, Section 3.1.B.7, during periods between biennialFire Protection Program program audits. Satisfactory performance against programmatic indicatorsPerformance allows NA to continue the biennial frequency for audits rather than increaseAssessment the frequency to an annual audit based on declining performance.SSA0808 Watts Bar 1/027/2009 WBN NoneNuclear Plant -FireProtection And LossPrevention -InterimReportSSA0808 (NPG) Wide -2/20/2009 WBN, SQN, BFN NoneFire Protection And LossPrevention FunctionalAreaQA.CH.09.005.Nuclear 12/08/2009 WBN, SQN, BFN The Fire Protection (FP) program assessment was performed to fulfill thePower Group (NPG) requirement of NADP-2, Section 3.1.B.7, during periods between biennialFire Protection Program program audits. Satisfactory performance against programmatic indicatorsPerformance allows Quality Assurance (QA) to continue the biennial frequency -for auditsAssessment rather than increase the frequency to an annual audit based on decliningperformance.SSA1 012 Watts Bar 12/08/2010 WBN NoneNuclear Plant (WBN) -Fire Protection -SiteAudit Report -2011 Annual WBN, SQN, BFNAssessment is currentlyin progressPage 2 of 2 }}