4 replies to this topic

[Padmakar Katre]

Dear All,
I am new in gas processing and currently working on a project related to the Natural gas Processing in which I have a Natural Gas which contains CO2 around 2 mol % and no H2S. As I was working over the Amine Sweetening Unit I found that MEA and DEA results good CO2 Recovery (almost 100 % in Aspen-Hysys) but with MDEA I found very poor CO2 recovery so for to know the basic process chemistry I searched on internet and I came across some quality papers related with the amine sweetening by Brayn Research and Engineering Inc in which I found that MDEA is selective for the H2S absorption than CO2 as there is no direct absorption of CO2 in MDEA. But in the Process Package which I got in which there is almost 98 % recovery of the CO2 and that is by using aMDEA so can anyone give an emphasis on the basic chemistry of the CO2 absorption in aMDEA.
While as in the older train of Natural Gas Processing we use MEA and we have almost complete absorption of CO2 and the Regenerator overhead stream contains some quantity of methane, ethane and H2O in this case I want purity of CO2 by removing the Methane like components ( water can be knocked down) but I don't know any of the procedure/methaod to get pure CO2 from amine sweetening unit as my concern is to use tha pure CO2 in our Urea Plant so as per the raw material Specification in Urea Unit the CO2 purity should be 99.5 % and and the balance 0.5% can be only water or any other inert like Nitrogen so Can anybody suggest me how to get rid-of this problem
1.Should I make some opertaing changes in my sweetening Unit or
2.Should I go for CO2 purification method Which I don't know.
Thanks in advance for your useful guidance and comments.

[Art Montemayor]

Padmakar:

Producing 99.5% pure CO₂ from a natural gas stream that contains no H₂S is very easy and I consider it a piece of cake.

I understand that you have an Acid Gas you want to treat. At that point, I get confused with your thread. For example, you state:

• “As I was working over the Amine Sweetening Unit”. Are you working on an actual plant? If so, what is its design features and capacity? Are you planning to modify it? Or are you starting a design on a new unit? If so, what is the feed gas composition?
• “I found that MEA and DEA results good CO₂ Recovery (almost 100 % in Aspen-Hysys) but with MDEA I found very poor CO₂ recovery so for to know the basic process chemistry I searched on internet and I came across some quality papers related with the amine sweetening by Bryan Research and Engineering Inc in which I found that MDEA is selective for the H₂S absorption than CO₂ as there is no direct absorption of CO₂ in MDEA”. You are getting the issue totally confused. First, and foremost, what you have specified is that you want to remove CO₂ from natural gas (that has no H₂S). This makes this operation an Acid Gas removal operation – not a sweetening operation. There is a big, big difference between both processes. You may not see it superficially, but there are operational differences when you need to remove CO₂ by itself or when you want to remove CO₂ and H₂S at the same time. What you have is an easy challenge – thank God. H₂S is much more troublesome and difficult than CO₂. Because you are only dealing with CO₂, all you have to apply is a simple MEA solution of approximately 10 to 15% MEA (wt) as the absorbent solution in a packed absorber. Forget about DEA and MDEA or any other Amine you are reading about.
• “Should I make some operating changes in my sweetening Unit?” Again, just exactly what is that you are doing? Is your unit existing or are you planning a new one?

Bryan Research & Engineering Inc is an outstanding resource for Gas Sweetening design and operation information and software. However, they seldom deal with pure CO₂ separation. Today, most natural gases contain H₂S as well and this is where BRE’s expertise comes into play. What you are describing is something else. And that is why I believe that you are reading the wrong books and literature. The expertise of CO₂ removal is very old (its older than me!). The Amine process was patented by Mr. R.R. Bottoms in 1933 – and it was based on removing CO₂ from steam reforming gases using MEA (with 20% + solution) for producing hydrogen.

You should be reading and studying the following books on the subject:

1. “Gas Purification”; Kohl & Riesenfeld (or Nielsen); Gulf Publishing
2. “GPSA Engineering Data Book”
3. “Gas Engineering & Processing”; John Campbell

These books deal specifically with CO₂ and its removal. I have designed, built, and operated CO₂ removal plants based on 12% and 20 % MEA, producing 99.9% purity and I used the referenced books as my primary basis. Forget about anything Aspen-Hysys (or any other simulation program) has to say about CO₂ removal. Simulation programs are merely number crunchers. They know absolutely nothing about process technology and know-how. Kohl & Riesenfeld contains more knowledge about gas purification than any simulation program will ever know.

If you give us a complete description of your scope of work and basic data, we can probably assist you in arriving at what ever stage in the project development you are seeking. The process may be old, but it works and is simple and easy to design and operate.

[Padmakar Katre]

Dear Art,
Thanks for your comments.Actually I am here in Algeria for 4 months assignment in M/S Sonatrach. I am working here in the simulation group of my compony(Engineers India Ltd). So I was doing the simulations of their existing Acid gas Removal Plant ( For sweetening word in earlier post- I am sorry) they are using MEA as the solvent. When I saw the natural gas feed composition, I found that it doesn't have H2S only CO2 and Helium along with some ppm level benzene and toluene. Just going through the Hysys Results, their running Plant analysis and the Licensor's Material Balance evrything was almost matching in which mainly the CO2 in the absorber overhead stream (very less) and the regenerator overhead stream (94 wt %) is almost the same.
now my client is coming with the another LNG train and for the acig gas removal section they got the process package ( From KBR Inc USA) in which they are using the MDEA as the solvent so when I used this data for simulation I got some absurd results like the CO2 conc in Contactor Feed Gas and the Contactor O/H Gas is almost the same means no removal of CO2. And after that I started searching to know the basic chemistry of this absorption (chemical) process. The results given by KBR are showing that the CO2 recovery is ok. So I was crazy to know the basic additives which are added in MDEA to make it active. But as it is patented so its very hard to know.
My concern was to recover the CO2 from first LNG train (94 % pure) and to use for Urea Unit.But the specifications of the CO2 required for the urea unit doesn't allow the any hydrocarbon presence so I want to remove these impurities and use this CO2 in the urea unit.
So just wanted to know the process for CO2 purification.Please ask for any other information if you need.
Thanks in advance.

[Art Montemayor]

Padmakar:

Please refer to the great article published by Jerry A. Bullin, John C. Polasek, and Stephen T. Donnelly titled “The Use of MDEA and Mixtures of Amines for Bulk CO₂ Removal” found at:

http://www.bre.com/p.....2 Removal.pdf

You may have it already, but I mention it for the benefit of others who may be interested in this topic.

I am very familiar with the Sonatrach Arzew LNG plant history since I worked with El Paso LNG in the 1970s when that was our base load plant for LNG imports into the USA at Cove Point, Maryland. I am also aware of what happened at Sonatrach’s Skikda LNG plant in 2004. Since you are on the recent KBR–related contract, I presume you are at Skikda and working on the replacement of the 3 LNG trains (20, 30 and 40) that were completely destroyed in January 2004 and the up-grading of the rest of the facilities there. As I understand the scope of the KBR contract, Air Products will be providing the Skikda LNG project its proprietary propane pre-cooled mixed refrigerant liquefaction process technology, with the Split MRTM refrigeration equipment configuration, and an MCR® main cryogenic heat exchanger – all rated for 4.5 Million metric tones/year of LNG production. The Sonatrach units at Arzew use the same liquefaction technology.

Now that I think I know the basis for your query and the background of the application, I can concentrate on what I think you are looking for. If KBR has picked MDEA for CO₂ removal, it must be, in my opinion, because of it’s attractiveness due to:

1. the exceptionally low reboiler duty requirement in the regeneration section;
2. the ability to employ a much higher concentrated solution (& circulate less solution);
3. the ability to design on a much higher acid gas loading in the rich solution.

There are, as one would normally expect, the traditional “trade offs” to endure:

• the MDEA can only effect a “bulk” removal of the CO₂ – i.e., the resultant natural gas product exiting the CO₂ absorber is going to contain a relatively high amount of CO2 (I would guess about 1%) and will have to be treated for total removal of CO2 downstream (either with MEA or with adsorbers);
• The MDEA cost is more expensive than other amines.

I know that the use of MDEA (like that of any other pure amine) is not patented. The technology is “open” for all to use. If you are working in harmony with Sonatrach, you should be running Bryan Research & Engineering’s simulation program ProMax – which is the best suited for this Amine Process simulation, in my opinion. I am sure that Sonatrach has the program and runs it. The customer service and counseling that BR&E gives its customers is very good and if I were you, I would look into that source of information for running any MDEA simulation calculations on the process. I may be wrong, but I don’t believe that KBR is planning on using any arcane “additives” to the basic MDEA in the absorbing solution. Plain, simple MDEA should work just fine in the bulk removal. This can be confirmed with KBR and the experts, BR&E.

If no sulfur (H₂S) is involved, I don’t think you should have any problem taking a profitable sidestream of the bulk CO₂ removal and simply compressing it, processing it and storing it as a liquid product in simple “Bullet” tanks at -8 ^oF and 250 psig. I’ve done that so many times that I forget the quantity. It’s very easy to compress and process CO₂ – if you are experienced in some of its idiosyncracies and “tricks”. It’s downstream use in the production of Urea should be a very logical and good application – if the economics fall into place. Additionally, this should be one of the best and most practical ways to "sequester" CO₂ (as the avant guarde, environmentalist managers like to express it) - rather than vent it to the atomosphere.

You mention that you expect to “remove these impurities”, but you don’t specifically identify what impurities you are expecting or where they come from. Are you expecting that some hydrocarbons will dissolve (or be absorbed) in the MDEA solution and later be flashed off with the associated CO₂ in the reboiler? Please explain.

I hope my guess on what your scope of work and application is was correct. I hope you are enjoying Algeria and its beautiful Berber people and traditions.

[Padmakar Katre]

Dear Chemical Engg Guru Mr Art,
First of all hats off to your reply and tonns of thanks for your precise comments.Yes I am enjoying Algeria and the people here and the most importantly the exposure to the Gas Processing ( In India we don't have LNG- for this reason I am so luck to have this exposure).
Now I am giving you the details of the the Regenerator O/H stream compositions and conditions which are as below-

Regenerator Ovh Off Gas

Temperature - 36 C
Pressure - 1.55 Bar (abs)
Mass Flow - 32670 Kg/hr

Comosition (Mol Fraction basis)

Helium - 0.00
Nitrogen - 0.000130
Methane - 0.023650
Ethane - 0.004222
Propane - 0.000842
i-C4 - 0.000065
n-C4 - 0.000091
i-C5 - 0.000009
n-C5 - 0.000004
n-C6 - 0.00
Benzene - 0.000013
Toluene - 0.000013
CO2 - 0.933377
Water - 0.037584
aMDEA - 0.00

Now I want to use CO2 from the above stream which is 93% pure the H2O I was able to remove by feeding this stream to the compressor and subseqently sending the compressor discharge to the K.O. Drum but the other impurities still remain as it is and I don't have any idea regarding the removal process e.g. any adsorbent which can retain these imurities and allowing the only CO2 to pass through.
Once again I will check the Raw material(CO2) Specification for the Urea Unit and I will let you know the same.
Thanks once again for valuable comments.