6 replies to this topic

[Brandon]

I'm faced with a design problem for a LNG plant and was just wondering what the major differences are between an acid gas removal (primarily carbon dioxide @ 10mol% and hydrogen sulphide @ 20ppm) system utilizing amine or potassium carbonate. any help is GREATLY appreciated!

[Zauberberg]

It's difficult to give some detailed comment on your query, but here you can see what are the differences between chemical/physical solvents used in gas sweetening, including their inherent advantages and disadvantages: http://217.174.18.60...pr/e-pr-551.PDF

General information about several gas sweetening technologies is being regularly published by Hydrocarbon processing. See: http://www.aimsgt.co...ndbook_2004.pdf

I would recommend you to have a thorough reading of Kohl & Nielsen's "Gas Purification" book, as it has been considered as a sort of industry standard for many years. There is also one interesting file I have found in my bag, see below.

Attached Files

•  Acid and Sour Gas Treating Processes.pdf   129.66KB   153 downloads

Edited by Zauberberg, 31 July 2010 - 06:20 AM.

[Brandon]

thanks Zauberberg! but i have seen conflicting text which states that activated benfield (potassium carbonate + DEA) process may or may not achieve the LNG spec of <50ppm CO2 and <4ppm H2S..same applies for the mixed amine process (MDEA + MEA). therefore i would like to seek help around to what would be more likely recommended for achieving that?

what do you guys think?

[Zauberberg]

Basically any of the processes can be tailored to meet product gas specifications, no need to worry about that issue. But the cost will be different, depending on how much you have to "stretch" certain technology in order to meet your requirements.

If CO2 and H2S are the only contaminants in the feed gas (i.e. no COS, RSH), your best choice is probably formulated amine like activated MDEA, Ucarsol, Flexsorb, Sulfinol. Also, lower Absorber pressures favor the selection of chemical/combined solvents. Physical solvents work very well at Absorber pressures >50 barg (in general). The problem with physical solvents is high co-absorption of hydrocarbons (Selexol, Rectisol, Ifpexol) so unless the feed gas is very lean I wouldn't choose physical solvent even if acid gas partial pressure favors physical solvents. Lower OPEX in such case would be offset by significant hydrocarbon losses and complicated/expensive recovery schemes.

As said, we cannot say much because you haven't provided even the basic set of data: feed gas composition, pressure, temperature, dowsntream processing scheme, your targets/constraints etc. If you cannot disclose process information, my advice would be to engage a consultancy company who will do the concept selection work for you.

Good luck,

[Brandon]

You have been a great help! but may i ask why your preference of the mixed amine process over the activated Benfield process?

My feed content would be primarily ~90mol% CH4 and 10mol% CO2 and H2S @ 20ppm with other inert gases in there coming in at 25C and approximately 40barg. would first like to focus on reducing the acid gas content down to <50ppm CO2 and <4ppm H2S.

[Zauberberg]

I didn't have intimate experience with the Benfield process so far, although I have seen or read about many gas sweetening plants. It doesn't mean that the Benfield would not meet your requirements - it is just my lack of "hands on" information about this particular technology. If I were at your place, I would certainly contact the Licensor and ask for preliminary design data, once when you submit all the required process information - then you will be able to compare CAPEX/OPEX with other process solutions. The major experience in gas treating I have gained during conceptual process design of a high-pressure, high-sour gas plant in Oman, and at that time we were having contacts with many technology licensors. Interestingly, but the client was never interested in Benfield technology. From the HCP Handbook you can see that it isn't frequently used for treating Natural Gas, so there must be a sound reasoning why is it like that.

Looking at a glance in your basic data, I would consider the following processes:

1. Selexol (as you have very lean gas - Selexol offers low energy requirements, carbon steel equipment, performs gas dehydration as well).
2. Activated MDEA (I used to work in the plant where feed gas contained 8.0 mole% CO2, no H2S, very effectively treated with aMDEA), you can add Ucarsol and Sulfinol to expand the list of formulated solvents.
3. DEA
4. See what Benfield can offer against these processes, in terms of CAPEX/OPEX, reliability, and life cycle cost. The best approach would be to obtain preliminary/budgetary quotes from process licensors. If you sound like a serious customer, they will certainly provide you with their proposals.

Hope this experience helps you out.

Edited by Zauberberg, 01 August 2010 - 02:51 PM.

[Zauberberg]

This is very interesting subject - perhaps a little bit off the topic but definitely worth reading.

Attached Files

•  GasTech2009 - Economical Option for CO2-Methane Separation in Produced Gas Containing a High CO2.pdf   101.86KB   94 downloads