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X65 (Gr. 448) versus X70 (Gr. 483) Line Pipe for Sweet Service, Liquid Transmission Lines 3
- Thread starter auzie5
- Start date
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1
- #2
LittleInch
Petroleum
Cost, availability, perceived to be easier to weld (especially manual welding), bigger margin between SMYS and UTS, but X70 is now being seen more and more.
BTW, the grade descriptions are now 450 and 485 in the latest pipe codes.
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
BTW, the grade descriptions are now 450 and 485 in the latest pipe codes.
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
LittleInch
Petroleum
I was referring to api 5l/iso 3183. However I would imagine other codes will catch up eventually.
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
I would suggest that auzie5 is in Australia where the project value considerations will still be the same as anywhere else in the world.
Steve Jones
Corrosion Management Consultant
All answers are personal opinions only and are in no way connected with any employer.
Steve Jones
Corrosion Management Consultant
All answers are personal opinions only and are in no way connected with any employer.
LittleInch
Petroleum
The question was "compelling argument" for X65 instead of X70.
All depends on what you find compelling to be. We seem to have lost the OP though....
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
All depends on what you find compelling to be. We seem to have lost the OP though....
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
It's not so far from Japan, Korea and China.
Steve Jones
Corrosion Management Consultant
All answers are personal opinions only and are in no way connected with any employer.
Steve Jones
Corrosion Management Consultant
All answers are personal opinions only and are in no way connected with any employer.
Whenever you think risk of corrosion eating up a thinner wall more quickly, or the potential for difficult to detect girth weld cracks due to too HF automatic welding,
exceeds the benefit of lower transportation weights.
exceeds the benefit of lower transportation weights.
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2
- Thread starter
- #15
I apologize for the delayed reply. I appreciate the input from all those who left comments.
To clarify, I am in Canada (not Australia). In Canada, CSA Z245.1-14 still references Gr. 448 and Gr. 483 (although as LittleInch mentioned, they will likely catch up with API 5L in time).
Background:
I have seen some operating companies whose main business is running upstream flowlines (between a wellhead and satellite) and therefore they require flexibility to convert their lines from sweet service to sour service as production gets sour over time. For that reason, their specs limit line pipe grades Gr. 448 (X65) or less with additional limits on macrohardness and max tensile strength (in accordance with CSA Z245.1 Sour Service).
However, those same companies will every now and again need to run a relatively long (ex: ~200km), big inch, downstream, sweet, sales oil pipeline. Unfortunately, they apply the same line pipe purchasing specs to their downstream pipelines which means we are left designing pipelines using Gr. 448 (with limits on hardness and max tensile strength) instead of using Gr. 483 (with no such limits).
Note on CSA Z245.1 Sour Service
CSA Z245.1 sour service requirements are less stringent than API 5L Annex H. It basically only prescribes limits on macrohardness, upper tensile strength, and nickel content. HIC or SSC are not mandatory but can be requested in the purchase order.
I have recently worked on a sour service emulsion pipeline at a SAGD facility where we were able to secure CSA Z245.1 SS Gr. 483 line pipe from the SeAH mill out of South Korea.
Note on Pipe Mills and Gr. 483:
Many mills we have worked with are much more comfortable making steel for and rolling X70 versus X65 since they have more experience with X70. Of course building X70 sour service is challenging for even the best pipe mills.
Note on Cost of Gr. 483 versus Gr. 448:
Yield strength is cheap. Steel tonnage is expensive.
Ex: $1,450 per short ton (2,000 lb) for Gr. 483 versus $1,400 per short ton for Gr. 448.
Typically we find that if we can shave off a fraction of a millimeter on wall thickness on a large mill run by going with X70 versus X65, the savings can be significant.
Note on D/t ratio:
Obviously there are limits to how thin you can build line pipe (for transportation, construction, risk of mechanical damage during operations, etc.). We have always tried to keep line pipe to around a D/t < 50 although we have run NPS 20 x 9.5mmWT on a few big projects.
Does anyone else have a rule of thumb in terms of D/t ratio for pipeline line pipe?
Note on Conventional Corrosion:
I have heard some not-so-compelling arguments about Gr. 483 being more susceptible to conventional internal corrosion versus Gr. 448 (ex: some water drop out in the line with some low levels of CO2, H2S dissolved within). I find this difficult to believe.
Anybody care to comment on conventional corrosion associated with Gr. 483 versus Gr. 448 (and keep in mind this is for sweet service, pipe spec quality sales oil; not sour service upstream production where we are at risk of HIC or SSC).
Other comments:
As WT decreasing, bulk material cost and bending costs decrease (no cost adder to bend higher grade pipe).
As WT decreases, there is less steel in the ground so the thermal loads applied at bends decreases which results in lighter wall thickness requirements for our bend pipe.
Pre-heat on Gr. 483 will be approx. the same as on Gr. 448 (~200 deg F depending on WPS) so no cost adder for higher pre-heat.
Welding consumables will be the same (6010-8010) for both grades. Welding costs should go down during construction since less filler metal required with lighter WT.
To clarify, I am in Canada (not Australia). In Canada, CSA Z245.1-14 still references Gr. 448 and Gr. 483 (although as LittleInch mentioned, they will likely catch up with API 5L in time).
Background:
I have seen some operating companies whose main business is running upstream flowlines (between a wellhead and satellite) and therefore they require flexibility to convert their lines from sweet service to sour service as production gets sour over time. For that reason, their specs limit line pipe grades Gr. 448 (X65) or less with additional limits on macrohardness and max tensile strength (in accordance with CSA Z245.1 Sour Service).
However, those same companies will every now and again need to run a relatively long (ex: ~200km), big inch, downstream, sweet, sales oil pipeline. Unfortunately, they apply the same line pipe purchasing specs to their downstream pipelines which means we are left designing pipelines using Gr. 448 (with limits on hardness and max tensile strength) instead of using Gr. 483 (with no such limits).
Note on CSA Z245.1 Sour Service
CSA Z245.1 sour service requirements are less stringent than API 5L Annex H. It basically only prescribes limits on macrohardness, upper tensile strength, and nickel content. HIC or SSC are not mandatory but can be requested in the purchase order.
I have recently worked on a sour service emulsion pipeline at a SAGD facility where we were able to secure CSA Z245.1 SS Gr. 483 line pipe from the SeAH mill out of South Korea.
Note on Pipe Mills and Gr. 483:
Many mills we have worked with are much more comfortable making steel for and rolling X70 versus X65 since they have more experience with X70. Of course building X70 sour service is challenging for even the best pipe mills.
Note on Cost of Gr. 483 versus Gr. 448:
Yield strength is cheap. Steel tonnage is expensive.
Ex: $1,450 per short ton (2,000 lb) for Gr. 483 versus $1,400 per short ton for Gr. 448.
Typically we find that if we can shave off a fraction of a millimeter on wall thickness on a large mill run by going with X70 versus X65, the savings can be significant.
Note on D/t ratio:
Obviously there are limits to how thin you can build line pipe (for transportation, construction, risk of mechanical damage during operations, etc.). We have always tried to keep line pipe to around a D/t < 50 although we have run NPS 20 x 9.5mmWT on a few big projects.
Does anyone else have a rule of thumb in terms of D/t ratio for pipeline line pipe?
Note on Conventional Corrosion:
I have heard some not-so-compelling arguments about Gr. 483 being more susceptible to conventional internal corrosion versus Gr. 448 (ex: some water drop out in the line with some low levels of CO2, H2S dissolved within). I find this difficult to believe.
Anybody care to comment on conventional corrosion associated with Gr. 483 versus Gr. 448 (and keep in mind this is for sweet service, pipe spec quality sales oil; not sour service upstream production where we are at risk of HIC or SSC).
Other comments:
As WT decreasing, bulk material cost and bending costs decrease (no cost adder to bend higher grade pipe).
As WT decreases, there is less steel in the ground so the thermal loads applied at bends decreases which results in lighter wall thickness requirements for our bend pipe.
Pre-heat on Gr. 483 will be approx. the same as on Gr. 448 (~200 deg F depending on WPS) so no cost adder for higher pre-heat.
Welding consumables will be the same (6010-8010) for both grades. Welding costs should go down during construction since less filler metal required with lighter WT.
auzie5 said:
Compositional and microstructural variations can play a role in corrosion performance of linepipe steels, particularly ferritic-pearlitic steels.
B Kermani, NACE Corrosion 2014, Paper 3813
Whether such differences will be significant between the two different grades produced at the same pipe mill which are likely to be processed in the same way with variations in intermediate and/or accelerated cooling for an acicular ferrite or bainite microstructure are impossible to predict.
J Bauer et al, Ironmaking and Steelmaking, Vol. 32, (4), 2005, pp325 - 330
Steve Jones
Corrosion Management Consultant
All answers are personal opinions only and are in no way connected with any employer.
- Thread starter
- #19
LittleInch
Petroleum
That's OK.
The bit I meant to respond to was the D/t. 100 is, IMHO, going a bit too far, especially for the smaller pipe sizes. There are a few design codes or guidelines which give minimum wt, and when you work them out are usually in the 80 to 90 range.
I think 50 is being rather conservative, especially for larger diameter pipe, but above 80 to 85 it starts to get dubious. The issue to me is also one of what percent would 1 or 2mm of corrosion make on the % of remaining wall thickness.
Below 15 to 20% wall thickness loss for a corrosion defect of certain length, the damage criteria assessment usually says no impact on operating pressure, but 30% or more for what is a relatively small corrosion defect starts to cause issues.
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
The bit I meant to respond to was the D/t. 100 is, IMHO, going a bit too far, especially for the smaller pipe sizes. There are a few design codes or guidelines which give minimum wt, and when you work them out are usually in the 80 to 90 range.
I think 50 is being rather conservative, especially for larger diameter pipe, but above 80 to 85 it starts to get dubious. The issue to me is also one of what percent would 1 or 2mm of corrosion make on the % of remaining wall thickness.
Below 15 to 20% wall thickness loss for a corrosion defect of certain length, the damage criteria assessment usually says no impact on operating pressure, but 30% or more for what is a relatively small corrosion defect starts to cause issues.
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
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