Thank you Dr. Jones.
N06040 does not meet the chemical composition requirements in clause 14.1.1.2 of NACE MR 0103, hence qualifications are required as per clause 11.
For caustic environment containing H2S and meet the definition of sour as per NACE MR 0103, does require testing and qualification for ssc? N06040 is not listed in NACE MR 0103 section 14.
Hi Dr. Jones,
The internally FBE coated pipes are available in client's storge, and they want to use them. The service is corrosive as acid gas is present and partial pressure of CO2 is above 30 psig. very little to no water will be present during operation of the pipeline. The concern is that...
Thank you LittleInch and EdStainless,
What I meant by large surface area of cathode to anode is that the system will be out of mass transport control. large amount of acid gas and small CS exposed to it. The gas is single phase with dew point control, so there will be little to no condensate.
Dears
The pipeline will have sour gas with H2S and CO2 with little to no water phase. The predicted corrosion rate is small and can be controlled with corrosion inhibitor and scraping with bare CS. Curranty, internally FBE coated pipes are readily available. Is it acceptable not to fix coating...
Correct Dr. Jones. This is Aramco. Curranty we are making the case for CS + CI + scrapping program which is inline with SAES-L-132 (Figure-1) and SAES-A-133 (Appendix A) CS evaluation for pipelines.
Hi LittleInch,
This is compressed gas coming from GOSP HP compressor. The inlet of the pipeline is about 170 F which is above the dew point of water. The arrival temperature is 160 F. ECE predict condensation and pitting rate higher than 5 MPY which mandate corrosion control as per clint...
Thank you Dr. SJones. My client uses Champion KR-2237X or ATROS Dodigen 1641X for downstream gas pipelines. I will contact the vendor and post the result here.
0707
Thank you for your reply. My inquiry is about pipelines corrosion caused by acid gas dissolved in water phase condensed from compressed gas. Top of columns corrosion happen at high temperatures. Severe damage can occurred in distillation columns and other equipment during downtime...
Dears,
Is corrosion inhibitors effective against pitting cased by H2S and CO2 for gas flowlines? The salt content is very low, so the line has low risk of scaling and under deposit corrosion. The ECE model gives around 20 MPY of maximum pitting rate and less than 1 MPY for general corrosion...
As far as I know, corrosion and scale inhibitors dosing are required for closed loop cooling water system. Galvanized A53 Gr.B is commonly used too. For CUI, external coating is important and it is one of the mitigation of CUI in API 571.
I agree with EdStainless. But what if condensation happen on top shell or head of the vessel and slide back to the clad/CS interface? Or is it assumed that the interface is always dry and no crevice corrosion will happen?
Dears,
Is it a sound engineering practice to only clad the water containing part of a liquid seal drum in sour service. Won't this create galvanic corrosion in the interface between the cladded portion and the bare CS portion?
Thank you
"ISO 15156-3/NACE MR0175 does NOT address the H2S cracking resistance of deposited weld metal at all. Thus, if you are asked to demonstrate how the dissimilar metal weld will be resistant to H2S cracking, how will you do it?"
But Dr. does this mean that weld overlay on cladded fittings are not...
"If you are going to put a dissimilar metal weld into sour service, how will the requirements of ISO 15156-2/3/NACE MR0175 be met?"
Thank you for your respond Dr.
What are the requirements of ISO 15156?
So if we have gas or dry crude services welding dissimilar metals is allowed as galvanic corrosion is not possible to occur? Is this a general practice is the oil and gas industries?
