Science 7 - LAND and SEA BREEZE and its Characteristics
F05 corrosive sulfurpresentation
1. The Evolving Problem of
Corrosive Sulfur in
Transformer Oil
IEEE/PES Transformers
Committee
Memphis, Tennessee
2. Knowledge Is Power SM
Apparatus Maintenance and Power Management
for Energy Delivery
Corrosive Sulfur in Oils, and
Transformers; Why it is Such a
Problem
Lance R. Lewand
Doble Engineering Company
3. What is Corrosive Sulfur?
US Definition found in ASTM D 2864 -
“elemental sulfur and thermally unstable sulfur
compounds in electrical insulating oil that can
cause corrosion of certain transformer metals
such as copper and silver”
4. Why is Corrosive Sulfur such a Problem?
• Reacts on contact with copper
• Does not require heat to promote the reaction
• Heat makes the effect more pronounced
• More pronounced in sealed systems
• May lead to deposition of copper-sulfur compounds
in the paper insulation
• Copper-sulfur compound deposition in the paper
insulation will lead to a weakened dielectric strength
5. The Problem
Ø Large power transformer and reactor failures
starting in 2000. Doble has recorded about 25+
units that have failed worldwide
Ø Many of these are units only 5 to 7 years olds,
(represents high asset cost)
Ø Very little advance warning:
§ No observable PD in tear downs
§ No generation of combustible gas even on the day
before
17. Mechanism
Ø Process
§ Corrosive Sulfur presence or formation
§ Attack of metal surfaces, copper sulfide deposition on
conductor
§ Deposition of copper sulfide in paper insulation
Ø Copper ions migrate to the insulating paper adjacent to
the conductor, react with corrosive sulfur compounds (or
transfers over to the paper as a copper/sulfur compound).
Ø Mechanism: Reduction of dielectric strength - voltage of
the conductor exceeds the insulating capacity of the
paper insulation and BIL rating. Result: arcing between
two or more turns/discs and a subsequent failure.
19. HV Winding Dissection
29th Turn
14th Turn
1st Turn
130TH Disk – near very top of transformer
Top
97TH Disk – area of failure
Middle
10 TH Disk – near very bottom of transformer
Bottom
24. Copper Migration/Deposition
The oil flow lines in the HV
Disk 130 winding take place in every
disk just not those shown.
The 3 black dots represent the
Disk 97
turn with the highest copper
found in the testing. The size
of the dot indicates the relative
HV concentration.
LV
Core
Winding Winding
Varnished
wire, no
paper
insulation
Disk 10
Designed
Oil Flow
26. Background/History
F.M. Clark – 1962 – “Sulfur compounds are inevitably present in all commercial
insulating oils” – Insulating Materials for Design and Engineering Practice
Transformer oils contain varying levels and kinds of sulfur compounds
Procedures were standardized to test for corrosive sulfur in the early 1950’s
Relatively few incidents since these standardized tests
-
27. Recent History
HVDC Converter Transformers and GSU’s
Reported:
§ CIGRE working group, Paris, 2004
§ ABB Review, 2004
§ IEEE Transformers HVDC section, Las Vegas, 2004
§ Doble Conference, Boston, 2005
§ ASTM D27, Reno, 2005
§ ABINEE, Sao Paulo, 2005
-
28. Conditions and Evaluations
Design and operation within industry standard practice
§ No unusual temperature or other environmental factors
§ Sealed units with relatively low oxygen content in oil
§ Relatively high and constant load
Investigation: Cuprous Sulphide, Cu2S
§ On insulation paper
§ On copper conductor
§ Other transformer components
-
29. SEM/EDX - Cu2S Deposition from HVDC
Unit
cps
6
O
4 C
2
Cu
S
Cu Cu
0
0 2 4 6 8 10
Energy (keV)
SEM EDX
-
30. Current Situation
Mineral oil/Transformer oil requirements
§ Oxidation stability more important to long life
Sulfur compounds desirable for enhanced stability
Some organic sulfur compounds act as peroxide scavengers in an oxygen-
rich oil
§ Life extension of insulation overriding concern
§ Relatively few cases result from corrosive sulfur
Standards were believed to be strong enough to prevent problems
Only recently (last 5-10 years): Standard tests not always conclusive
-
31. ASTM Test D 1275
Corrosive Sulfur in Electrical Insulating Oils
.
§ ASTM D 1275 used since 1953 – Superseded ASTM D 117
§ D 117: 5 hours at 100oC. D 1275: 19 hours at 140oC.
§ F.M. Clark and E. L. Raab, Proc. ASTM, Vol. 48, 1948, pp. 1201- 1210:
§ Demonstrated inadequacy of D 117 at this low temperature and duration.
Could not identify corrosive oils
§ For same level of tarnish, D 117 took 432 hours, but only 5 hours at 140 oC
(temperature chosen for D 1275).
§ D 117 sensed only free sulfur.
-
32. Examples of Copper Corrosion Tests
ASTM D 1275: Copper Based Test
Oils at 140oC, 19 hrs
New oil
(Plant oil)
Field Unit 1: Very Field Unit 2:
slightly corrosive Slightly corrosive
-
33. Definition of Corrosive Oil - ASTM D 1275
Appearance of Copper Strip
Noncorrosive:
Orange, red lavender, multicolored with lavender, blue or silver, or
both, overlaid on claret red, silvery, brassy or gold, magenta overcast
on brassy strip, multicolored with red and green showing (peacock)
but no gray
Corrosive:
Transparent black, dark gray or dark brown, graphite or lusterless
black, glossy or jet black, any degree of flaking
-
34. DIN 51353 – Detection of Corrosive Sulfur –
Silver Strip Method
§ Prüfung auf korrosiven Schwefel - Silberstreifenprüfung
§ Deutsches Institut für Normung e. V.
§ Used in IEC (mostly outside USA)
§Previous Editions: Jan. 1965, Sept. 1977
§Current Edition: Dec. 1985
§ Adopted in response to many color shades on copper
§ Same sample configuration but silver strip
-
35. Examples of Silver Corrosion Tests
DIN 51353: Silver Based Test
Oils at 100o C, 18 hrs
New oil
(Plant oil)
Field Unit 1: Very Field Unit 2:
slightly corrosive Slightly corrosive
-
36. Definition of Corrosive Oil - DIN 51353
Appearance of Silver Strip
Non-corrosive:
No noticeable affect, or a weak golden yellow discoloration
Corrosive:
Light grey or brown shade to a distinct grey up to black
-
37. ASTM D 1275 vs. DIN 51353
Two tests with very nearly the same result
ASTM D 1275 DIN 51353
Copper strip in oil Silver strip in oil
Nitrogen bubbled Loose fitting cap
1 minute (oxygen)
19 hours @ 140oC 18 hours @100oC
-
38. Alternative Corrosion Tests
n Doble Engineering Extended/Modified ASTM D1275
Same parameters as D1275 except:
n 48 hours @ 150oC (replacing 19 hours @ 140 oC)
n ASTM D 5623 – Sulfur Compounds in Light Petroleum by Gas
Chromatography and Sulfur Selective Detection
n Potentiometric titration method to determine mercaptan level
n ABB Covered Conductor Corrosion & Deposition (CCCD) test
-
39. Why different tests?
n Not all sulfur compounds react in same way
n Environmental dependences:
Presence/Absence of oxygen
Different temperatures
Presence of passivators
n Not all transformers operate with same conditions
-
42. Summary: Methods to Study Problem
n Cu2S deposition reproduced in laboratory
Test materials & environment similar to real transformer
service, e.g. temperature, oxygen content etc
n Result: Cu2S deposition can be reproduced
On conductor
On paper facing the conductor
On free cellulose surfaces
Deposition can occur at low temperatures, 80oC and 100oC
Time required for test 12 weeks at 100oC, 3 weeks 120oC
-
43. Promising Tests
§ Metal strip test method such as D 1275 --higher temperature and longer
time
Produces quick screening test
Somewhat sensitive to oxygen
Proposed to ASTM but not accepted – Too few actual cases
§ New ABB CCCD test method preferred
Produces results we want to avoid in transformers
Relatively time consuming
Reliable, produces results close to real case
-
44. Conclusions
n Sulfur and potentially corrosive sulfur have always been present
in transformer oil
n Currently available tests not always completely capable of
finding potential problems
n Further development and verification of new standard methods
should be (and is) being pursued
-
45. The Basics of Crude Oil
Selection and Refining
IEEE/PES Transformers Committee
Fall 2005 Meeting
46. Crude Oil Selection
Considerations
1) Availability/Logistics: How much is there and where is it.
How does it get to the plant?
2) What does it look like: Can we run it? Sweet/Sour vs.
Plant Design
3) Will it work?: Target Markets and Specifications
Sulfur evaluations are typically for overall sulfur content only
– no speciation of specific sulfur compounds is necessary
47. Major Refining Steps for Naphthenic Oils
Step Objective
Distillation Split into desired Fractions for:
Viscosity
Boiling Range
Volatility
Flash Point
Hydrotreating Convert Aromatics to Naphthenics for:
Better Heat Stability
Better Color Stability
Control of Compatibility
Removal of Impurities
Solvent Extraction Removes Aromatics which:
Improves Stability
Reduces Compatibility
48. REFINED LUBE PROCESSING
NAPHTHENIC
CRUDE
UNIT
VACUUM HYDRO-
DISTILLATION GENATION
EXTRACTION
OR FINAL
SOLVENT
DISTILLATION
HYDRO-
CRUDES GENATION
OR
AROMATIC OR
FINISHED
EXTRACTS PRODUCTS
OR
EXTRACTION
SOLVENT
REDUCED
CRUDE
AROMATIC
2005 Calumet EXTRACTS
Lubricants Co.
50. Two new Transmission lines in
the Brazilian Grid :
North/South II
Southeast/Northeast
51. North/South Line:
o 30 single phase reactors 550/v 3 kV,
55 MVAr plus 6 spare units.In
service 1.5 years.
12 units with oil “A” and
24 units with oil “B”
IEEE TC – Fall 2005
52. Southeast/Northeast Line:
o 03+1spare reactors 500/v 3 kV 45.3 MVAr
o 06+2spare reactors 500/v 3 kV 33.3 MVAr
o 12+2spare reactors 500/v 3 kV 66.6 MVAr
o 09+2spare reactors 500/v 3 kV 50.0 MVAr
In service 2.5 years. All units with oil “A”
IEEE TC – Fall 2005
53. o All reactors were filled with oil
tested according to ASTM D 1275
and the result was “non corrosive”.
o After appoximately 6 month in
service some units of North/South
line filled with oil “A” presented
corrosive sulfur when tested with
the same method.
o Units filled with oil “B” did not test
positive for corrosive sulfur
IEEE TC – Fall 2005
54. o In march 2005, after approx. one year in
service, one of the units of the
North/South line with oil “A” returned to
factory, without having failed, to be
examinated.
o A new heat run test with sensors in the
winding indicated a maximum hot spot of
59.8°C ( copper/ambient).
o DP of paper varying from 900 to 1000
o The copper of 1/3 of the winding was
contaminated with copper sulfide that
migrated to the first two layers of
insulating paper.
IEEE TC – Fall 2005
57. Test made with reactor conductor samples
IEEE TC – Fall 2005
58. o August 2005 one of the 33.3 MVAr
reactors of the Southeast/Northeast line
that failed after 2.5 years in service was
opened in the factory.
o All the copper was contaminated with
copper sulfide.
o Until the end of september 2005 eight
reactors from different manufacturers of
this line failed, all with oil “A”
IEEE TC – Fall 2005
59. Failure in the second disc from the top
IEEE TC – Fall 2005
61. o There is also a transmission line of
another utility with:
6+1 spare reactors 550/v 3 55 MVAr
6+1 spare reactors 550/v 3 35 MVAr
o All filled with oil “A” with corrosive sulfur
and energized since the end 2002
(approx. the same age of the
Northeast/Southeast line ).
o No one failed.
IEEE TC – Fall 2005
62. o To finish three conclusions and one
question:
1- The copper sulfide migrates from the
conductor to the insulation paper reducing
it´s dielectric strenght.
2- The corrosion of the copper conductor
begins with temperatures below those
allowed by the standards and is more
significant the higher the temperature.
3- The contamination (copper and paper)
increases with the time.
o 1- Why some TL are more subjected to
failures than others? (Transients ?)
IEEE TC – Fall 2005
64. Corrosive Sulfur
Since December 2004 , 12 Single Phase Shunt Reactors 525 kV
of the North – Southeast Brazilian Interconnection failed due
to the problems with corrosive sulfur (7 units delivered by
Siemens and 5 units by another Brazilian manufacturers)
Recently, a second single phase GSU units of Nuclear Power
Station – Angra 2 failed.
The ASTM special tests was performed in the oil of all four
units and it was detected the presence of corrosive sulfur in
the oil of the two failed units.
The failure investigation showed a high degree of copper
sulphide contamination on the paper insulation of the tap
leads and HV winding conductors .
The most likely cause of the failure is still in discussion.
23.10.2005
69. Disc conductors from the upper part
Reactor Failure
outer strand of twin Inner strand of twin
Turn at the outer diameter Turn at the inner diameter
23.10.2005 Inner strand of twin Outer strand of twin
70. Reactor Failure
Copper Sulphide deposits at different
disc locations
23.10.2005
82. 23.10.2005 Source : EPRI Report 09/2005 to Eletronuclear – Mr. Nichols C. Abi-Samra
83. Oil Passivator (Nypass)
Conductor
surface
The passivator protects the copper surface against to
the new attack of the corrosive sulfur.
The passivator can stop the cooper sulphide
generation but it is not able to remove the existing
23.10.2005
deposits on the paper insulation.
84. Recommended Actions
•Oil Corrosive Sulfur test performs using the
ASTM modified test (150 ºC and 48h with O2
removed).
•Addition of Passivator where the corrosive
sulfur attack are still not critical, according to
oil supplier recommendations.
23.10.2005
85. Open questions
• Critical operating temperature level and
surround conditions.
• Breakdown mechanism
•Diagnostic method to evaluate the
contamination degree and the insulation
strength reduction.
• Long term performance of the Passivator.
23.10.2005
87. Transformer Oil Test Results
Modified ASTM D-1275
• 198 transformer tested
• 19% (38) failed the Modified test
• 2.0% (4) failed the standard D-1275 test
• All were built between 1998 & 2004
• 4 manufacturers transformers involved
88. Transformer Oil Test Results
Modified ASTM D-1275
• No Significant Indicators from oil screen
tests
• 218,000 gallons of oil
• $22 million transformers at risk
• At least 2 oil refiners involved one
unknown
89. Transformer Oil Test Results
Modified ASTM D-1275
• Both inhibited and uninhibited oils
• To stop the corrosive sulfur issue
– adding metal deactivators to the transformer
oil at 100 PPM.
– Require any new oil shall pass the Modified
D1275 test before receipt.
