10 replies to this topic

[Alawi]

What is the recent typical value for salt content in Arab light crude measured in PTB? I recently heard that in addition to the "common" forms of organic and inorganic chloride in crude there is some type of crystalline chloride that forms due to specific up stream operation conditions in the oil wells and this crystalline chloride may not be clearly accounted for when measuring the salt content of the crude but chloride content in the water from the distillation column over head receiver will show an increase when back calculated giving more than expected from the originally measured value in the crude. Does any one have any feed back on this issue?

May peace be upon you.

[Zauberberg]

Hello,

This actually applies for organic chlorine compounds. They cannot be removed by desalting process, what happens usually is that most of them decompose in the furnace upstream of atmospheric tower when HCl vapors are generated. These are being carried overhead, and create extremely corrosive environment. I have read several articles explaining how relatively small amounts of organic chlorides can cause total failure of CDU overhead condensers in just a few hours. Apart from that, if carried downstream to naphtha hydrotreater and catalytic reformer, the damage is doubled.

Non-extractable chlorides do not occur naturally in crude oil. Crude oils can become contaminated with non-extractable chlorides in a number of ways:

· From chemicals used in enhanced oil recovery processes
· From chlorinated solvents used in crude oil production, transportation and storage (through use of these solvents for down hole paraffin control is no longer permitted)
· From chlorinated additives used in production, transportation and storage (possibilities include wax crystal modifiers, biocides, corrosion inhibitors, flocculation additives, emulsion breakers)
· From unmonitored disposal of various chlorinated compounds into crude oil storage tanks, pipelines, or refinery slop systems
· From leaded gasoline
· Asphaltene-chloride salts
· Oil-coated inorganic salt crystals

I remember there was a good online library with plenty of resources related to CDU corrosion and fouling. It was more than 3 years ago when I was looking for this data. Do a Google search.

Best regards,

[Alawi]

Thank you

[Zauberberg]

Another comment: you can track these compounds by analizing crude oil from the storage tank (CDU inlet stream), and sample of desalted crude in parallel. Standard method for organic chlorides in crude oil is ASTM D4929.

I'd also suggest you not to use conductivity methods for salt content determination in crude, because they account for all polar and ionic species present in the sample - this way you'll have fake measurements.

[Alawi]

Dear Mr. Zauberberg,

Again thank you. Unfortunately we currently process our crude without a desalter on line.
The current method we use to measure the salt content in crude is by conductivity methods, according to ASTM test method D3230 (opposite of what you suggested
). I have to say that the results are rather confusing we are getting low values for salt content in the raw crude but high chloride concentrations in the main column overhead receiver.
It was suggested be an expert to perform a rather pragmatic testing approach to test for the chlorides, the results obtained were more close to realty than the conductivity method, the new test gave higher chloride values.
The new test is simply strong mixing of a volume of chloride free water with a volume of crude, separating the water from the crude, then measuring for chlorides in the separated water.
At this point I can not accurately analyze the difference in results between the two methods due to an existing possibility of needed calibration for our conductivity measuring device and that the second test was performed with out any documented test method by the ASTM,AP1,..etc.
You have mentioned “a good online library” with plenty of resources related to CDU corrosion and fouling, any flash backs?

Kind regards

[Zauberberg]

Alawi,

That's quite strange - operating a CDU without desalting unit can be justified only if salt/water/BSW content in your crude is extremely low. Nowadays, dubble or even tripple desalting is employed in petroleum refining - as crudes become more difficult to process (especially so-called opportunity crudes with high residue content, salt content, high asphaltene load etc.). Targeting 10ppm chloride level in overhead drum should be the reference for mitigating corrosion concerns. On the other hand, injecting caustic upstream/downstream of desalter has certain impact on downstream processing facilities - visbreaker, FCCU, residue cracker etc.

You need desalter, believe me - if your crude salt content is above 100ppm. That's the place where the battle against CDU/VDU corrosion starts. Choose a correct method for salt analysis, regardless of the cost - it's better to have one good analysis per week than 10 useless analyses per day. I know that, it is my school of life. I've spent more than two years running CDU and VDU as process engineer and plant manager, and one of the biggest issues I had was to convince refinery management to approve investment for proper desalter level control (Agar or Synetix/Tracerco probes) and adequate laboratory methods for analyzing crude salt content.

In combination with good desalting, overhead system waterwash is an excellent shield against corrosion. By recycling a portion of condensed stripping steam from the overhead receiver boot, you will maintain a sufficient amount of liquid water at the inlet of overhead condenser - just enough to avoid low pH of so-called "first water droplet". This way, you will also reduce condensing capacity of overhead coolers (LMTD will become lower with water injection), and this has to be overcome by installation of additional surface area. Furthermore, if your CDU tower top temperature (or pumparound/reflux return temperature) is lower than the calculated water dew point, you will experience severe corrosion in top pumparound circuit and top trays in the tower.

I am ready to help you as much as I can, if you can provide additional data. And, as far as internet links are concerned, my memory beats me - it was really long time ago. However, doing an intensive Google search on CDU overhead corrosion will give you many results. I am uploading one PTQ article for your reference.

I remember one really interesting guy from The Netherlands, professional corrosion engineer and member of NACE commitee: Henk Helle. He was very kind and, at that time, provided me a lot of quality data regarding refinery units corrosion. You can apply for his book (excellent material) or for attending his worldwide known courses. The website address is:

http://www.corrosioncontrol.nu/

Best regards,


[attachment=826:ADU_Over..._Article.pdf]

[Alawi]

Hello zauderberg,

I will arrange to provide you with as mush relevant data, thank you for both the ptq article & the link to corrosion control site. Actually the expert I referred to is from the same company whom the author of the ptq article works for and last week he referred a team from our company to the same article.
One piece of good news is that we are in the final steps of purchasing a desalter, may be a bit late but at least its happening.
I totally approve with your "school of life" it's better to have one good analysis per week than 10 useless analyses per day . would it be to much to ask what methods are applied to measure the salt in crude content at your refinery. Currently we use the conductivity method, also we have recently requested to purchase the required reagents and equipment needed to perform the Standard test method for organic chlorides in crude oil is ASTM D4929.


Good day

[Zauberberg]

The methods I know are: ASTM D6470 (potentiometric) and IP-77 (extraction and color indicator titration). I left refinery 8 months ago, so I don't know what are the outcomes of new level measurement technology and salt content tracking - if projects are executed completely.

Do you inject any caustic in crude oil stream, and have you experienced fouling in the preheat train upstream of process furnace?

[Alawi]

I will check the two methods you mentioned and see if are able to apply them at our lab.
Yes, we do inject caustic soda (spent soda from LPG caustic treatment units)in the crude oil stream and yes we are experiencing some degree of fouling in the preheat train. We have started a chemical treatment program (Anti fouling injection) and it has given some improvement.

[Zauberberg]

Hot preheat train fouling is - usually - a consequence of elevated salt content in crude. Due to higher temperatures in this section of CDU, certain amounts of free water (which is always present in the system) are being dissolved in hydrocarbon stream, leaving the residual water supersaturated with inorganic salts. And they start to precipitate as solids. However, you can never be 100% sure this is your case, because there are some other possible culprits, such are:

- Caustic overdosage (overdozing is just as bad as not injecting at all)
- Undersized heat exchangers
- Incorrect fluid allocation

The only way how you can be sure about this, is to perform hydraulic analysis of existing heat exchangers and see what are the velocities (consider maximum throughput and turndown). Also, fouling deposits analysis during plant turnaround is highly desirable.

[Zauberberg]

I apologize, in my previous reply it should have been stated OVERSIZED heat exchangers.
Sorry for the inconvenience,