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[Amclaussen]

Dear forum coalleages:

We have a tough design task ahead of us. We need to analyze and approve or Duisapprove the design of a large (55 MMSCFD) DEA Gas Sweetening unit that is to be mounted on an Offshore Platform, thus complicating the design as it has to be built with a very limiting physical size and be capable of running without problems at the same time.  Years ago, I had a lenghty chat with an expert from Houston discussing the many design challenges of the amine units.  Very few units work properly in our country, all of them operated by PEMEX.  One topic that was discussed was the physical size limit for a Direct Fired Unit.  The expert told me there was a size and capacity limit for a Reboiler (Direct Fired, natural gas, 30% DEA, horizontal kettle).  That gentleman pointed to the several disavantages of using a direct fired reboiler vs a Thermal Fluid Hot Oil Reboiler. He told me that a Direct Fired one would need to be limited to a maximum size in order to have an acceptable thermal behaviour, since simply enlarging (scaling up) an existing design was going to suffer from localized hot spots resulting from a large horizontal flame inpinging uder the upper part of the fire tubes, and that the high temperature of the required large burner flame was going to cause amine thermal degradation.

In the design (made by others), this limitation appears to be ignored, as the resulting size is about 15 feet diameter by 46 ft. long, being two Reboilers supplying heat for the 55 MMSCFD plant. DEA circulation is about 400 GPM and desired sweetening is for a sour gas with about 3.1% CO2 and 2.99% H2S, to achieve a curious PEMEX spec of around 14 ppm H2S max.  Initial proposed Reboiler design has four large Maxon brand burners with integral centrifugal blowers, placed on the inlet ends of four 24" diam fire tubes that have 3 60° elbows to achieve a 180° return, making a two pass exchanger. Nobody has proposed the addition of a forced circulation pump on the shell side, and as it is, there is a single inlet toi the shell and a single outlet behind the baffle inside the Reboiler. My main preuccupation is that they simply scaled up (doubled, would be more appropriate to say) the drawing from an old design, in order to reach the required size to meet the thermal load, but without checking amine film temperatures or heat flux. (It was specified a value of 8,000 to 10,000, but without saying "maximum", and as I see it, this range will undoudtely be exceeded in the first 10 or 15 feet of flame lenght (the designer simply reported complying with the specified value, but omitted saying it is a mean value and that the maximum will be largely exceeded!).

 

Any valuable opinions and guidance on this problem?

 

Sincerely, Amclaussen, Mexico.

[Art Montemayor]

 

Amclaussen:

 

Before going any further into this discussion, you need to specify the total DUTY (Btu/hr) of the subject reboiler(s) – as well as the total heat transfer area being proposed by the designer (whoever that might be).  Reboilers are rated by their duty, not the flow rate of process fluid being heated.

 

Additionally, please explain why diethanolamine (DEA) is being applied to remove both acid and sour gas instead of a much better and more efficient aMDEA?  I realize that if PEMEX went with an additive amine it would have to participate in a licensed process agreement – but this is not a new or strange design necessity for PEMEX, who has done this many times in the past.  aMDEA has much less reboiler duty required than DEA, so this would make a platform-based reboiler smaller --- which is the main priority on process design for platforms.

 

Other questions also arise on this application:

• Why is a sour gas being treated on an offshore platform?  Two reboilers that take up 15 feet by 46 feet long is a very large amount of space to take up on valuable offshore real estate.
• What is to happen to the product sulfur (presuming a Claus plant is also a necessity in order to avoid noxious and toxic H₂S effluent in the Gulf of Mexico - assuming that is where this is all planned)?
• Even if a Claus plant is proposed, there is still resultant bad tail gas to account for.  What is to happen with this?

 

55 MMScfd of a sour natural gas stream is not an extremely large flow rate as natural gas streams go.  But 400 gpm of (30% ?) DEA seems to be greatly exaggerated.  Without the reboiler duty, this is hard to relate to.

 

If gas turbines are employed on a platform (as is the usual case), GOM producers/operators usually employ a hot thermal fluid heated by turbine exhaust for similar reboier duty - such as TEG dehyrators.  This is a safe, efficient, and better controlled method.  An 8,000 Btu/hr-ft² reboiler flux is OK; I’ve specified 6,000 Btu/hr-ft² in the past for direct-fired heaters.

 

I would not specify a direct-fired reboiler for the obvious reasons – but more specifically for the very large, expensive, size.  Maintenance on this size of unit would be horrendous on a platform.  I also fail to understand why forced circulation is not employed instead of relying on natural convection currents that make a heat transfer application very big and detrimental when applied to an offshore platform.