Sour service vs sweet service in pipeline design and pump selection

[farhadsh]

Hi there,
CSA Z662 defines sour system by considering H2s partial pressure in a pipeline.
I have crude with total Sulphur of x% mass.
Is total Sulphur % can represent H2S in crude? What is limit to consider sour liquid?
My crude includes X % mass of water. Can I assume total Sulphur and water can mix and produce H2S?
I need this info to decide pump material and design to be suitable for sour service vs sweet service.

 

[zdas04]

You really need to look at the species of sulfur you are dealing with. Most of the reactions between the sulfur species and the water (or the crude) have already run to completion over geologic time. One possible reaction results in stable H2S. There are others. Get an analysis before you cut your wrists and buy SS piping.

David Simpson, PE
MuleShoe Engineering

In questions of science, the authority of a thousand is not worth the humble reasoning of a single individual. Galileo Galilei, Italian Physicist

 

[wangduyu]

Is there any data regarding H2S Percentage provided by crude oil vendor? that one will be your basis for design.

The mixture of crude oil, including the H2S percentage, shall be availble before the refinery designed, even if the crude oil goes into the process line is a mixer of serveral different oil company.

 

[farhadsh]

What I provided above was based on crude samples analysis. Analysis specifiesz zero H2s. It specifies percentages of water, sediments, total sulphur,Total acidity and many chemical componds.

Here are my questions:

To check if crude is considered sour by CSA, one has to calculate H2S partial pressure. Can I assue crude is not sour since alanysis specifies zero H2S; or I should consider total sulfur can be a sign that H2S can form or be causious at least? I have seen somewhere that if total sulfur in crude is more than 0.5% weight, crude should be considered as sour.But as David mentioned H2S reactions should has already been completed if that was the case and alanysis should have proved it.

Assuming crude has no H2S and assuming it is not considered sour liquid any more, should I consider stress craking corrosion when I am selecting material

Is NACE spec for pump and piping material selection applicable to sour service only?
or if we have sweet service plus total sulphur we need to meet NACE?
PLease share your thoughts

 

[wangduyu]

Farhadsh, quite difficult situation, in crude oil, Sulfur is in many different forms, pure S, H2S, S02 and some other RSH and so on.

But if the lab is certified to issue such number as reference, it is good news.

Keep some space for poor quality crude oil, when you select material, one day, high quailty crude oil will be too expensive, those plant capable to handle sour crude oil will survive.

Sour crude oil from mid-east may have a total sulfur above 2%(weight).

 

[georgeverghese]

Farhadsh,
You may get more responses if you were to transfer or copy this posting to the materials engineering / corrosion engineering forum ?

 

[LittleInch]

You need to figure out what the cost difference is if you design for sour crude vs sweet. Often this isn't much or anything, just getting materials to NACE requirements.

You really need to talk to a materials engineer to see what the actual impact is on your particular system, but if you design for a relatively small amount of H2S it might not be so bad.

AFAIK, the key thing to consider is H2S, not total sulphur. Total sulphur is important for the "quality" of the crude and how it can be distilled and sold or require treatment to lower the sulphur so that when it gets burnt it doesn't emit SO2 in large amounts, but not for transport of the Crude itself.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[EmmanuelTop]

For zero H[sub]2[/sub]S crude, why would you consider sour service? The term "sour" you are referring to (for crude oils containing more than 0.5 %wt Sulfur) has nothing to do with sour service materials. It simply defines the levels of total Sulfur content which affects hydroprocessing requirements for crude oil products (Naphtha, Kerosene, Diesel, VGO). Obviously, the more Sulfur in the crude oil, the more severe will be hydroprocessing of distillates in order to reach product specifications. And this costs money.

The Sulfur you are talking about cannot be detached from Hydrocarbon molecules unless you apply high pressures, high temperatures, catalyst, and high partial pressure of Hydrogen in hydroprocessing reactors in refinery. In transportation you are far, far away from these conditions.



Dejan IVANOVIC
Process Engineer, MSChE

 

[EmmanuelTop]

I found an example - see attached. This document shows Sulfur content and distribution for several marketed crude oils. You will notice that Sulfur content increases with distillation cut or Carbon number (i.e. each Hydrocarbon fraction contains more Sulfur than the adjacent lighter fraction, and less Sulfur than the adjacent heavier fraction). Mercaptan Sulfur decreases with increasing Carbon number.

You can also see which are the common Sulfur compounds and categories found in crude oils.

Dejan IVANOVIC
Process Engineer, MSChE

 

[farhadsh]

Thanks to everyone. Now I know total sulfur in crude does not represent H2s and Sour definition.

 

[georgeverghese]

The attachment referred to in this link might help

http://www.documentation.emersonpro...iclesreprints/nace_overview_corrosion2004.pdf

It looks like NACE 0103 has further expanded on the limits stated in NACE MR 01-75.