11 replies to this topic

[PSB]

Hi everyone,

I have a very basic doubt regarding Gas Processing.

In a Gas Processing facility consisting of a Compressor and a Glycol Dehydration Unit (GDU). Which sequence is most desirable from the below and why?

1) GDU upstream of the compressor
2) GDU downstream of the compressor.

In my case The Gas (75.6 mmscfd) from the slug catcher is coming at a pressure of 450 psig and 132 F and the sales gas at OSBL is required at 700 psig and 128 F. The guarantee parameters for sales gas are 0.7 lb / mmscfd of water.

Thanks.

[Fr3dd]

Hi PSB,

I have not experience with dehydration units; but, considering basic process engineering principles, i would choose the first one (first GDU, then compressor) for the following reasons:

1. Increasing the pressure of the gas before dehydration means that you will need equipment in the GDU to be suitable for higher pressures (more pressure = more capital costs).

2. I don't know your water content in the inlet gas or the type compressor you're planning to use but you have to consider that most of compressors are sensitive to moisture in gas streams so, if you have the oportunity to have the compressor downstream the dehydration unit, go for it!.

Hope this helps.

Regards,

[paulhorth]

PSB,
I would not agree with the previous post. I have worked on the design of many gas treatment plants and it is common to have the glycol contactor on the discharge side of the compression, at pressures up to about 70 barg. Higher pressures can increase the tendency for hydrocarbons to dissolve in the glycol and can also affect the design of the contactor internals because of the higher density of the gas. In your case at 700 psi, or 48 barg, these problems will not be significant and this pressure is well within the range of established practice.

Obviously, the contactor will have a higher design pressure than one on the suction side, but it will also be smaller in diameter, and these two factors act in opposite directions on the vessel weight and cost and will tend to cancel out. One benefit of having the drying at higher pressure, is that if the gas is saturated at suction conditions, then some water can be removed by cooling and condensation at higher pressure on the discharge side, which reduces the load on the glycol unit, allowing lower glycol circulation and lower cost for the regeneration.
If the gas drying used mole sieves instead of glycol then the reduced water load at higher pressure could represent a significant saving in sieve volume.

I don't think water vapour in the compressor would be a problem, provided the suction gas is free of liquid droplets. The world is full of compressors operating in such service,

Paul

Edited by paulhorth, 20 September 2012 - 03:46 AM.

[Art Montemayor]

Based on my experience, Paul Horth is correct in his comments. I have participated in the design, fabrication, and operation of various TEG dehydration units – both onshore and offshore – and continue to do so today. TEG (Triethylene glycol) is usually employed in natural gas dehydration at nominal pressures of 100 barg and is done so for the basic reasons Paul has mentioned. Definitely, any adsorption process is out of the question in this application. Adsorption is a cyclic operation; TEG is a continuous one. The sales gas specification is not for ppm’s of water, so TEG is a natural choice. I believe the OP has made an error in stating the sales gas water content is 0.7 lb/MM scfd. I think it should read 7.0 lb water/MM scf. This is an almost international standard for transporting natural gas by pipeline, as established here in the USA. This water content is based on a net volume of gas – NOT a daily rate of gas.

Additionally, it will be found that this application, mainly because of the capacity size and scope of work, will entail the use of a centrifugal compressor that is not sensitive to any water in the saturation gas as a reciprocating machine would be. Saturated gas is not a problem, although efficient liquids separation is a priority in TEG pre-treatment. It always makes for process common sense to squeeze the majority of the water in a saturated gas using pressure and post cooling at ambient conditions. In this specific case it will be found that the majority of the water content will be removed by compression and ambient cooling and dropped out as condensate in a vapor-liquid separator prior to introduction into a TEG contactor at the 700 -800 psig discharge pressure of a centrifugal compressor. This would be the conventional way to handle this dehydration operation because it removes a large dehydration load from the TEG regeneration process.

[Bobby Strain]

I agree with all of the recommended solutions. Of course, the proper answer is to evaluate for the lowest cost operation. Both initial cost and operating costs. It should take no more than a day to do so if you use vendor data for the TEG unit. And your employer will be pleased that you have selected the best option.

Bobby

Edited by Bobby Strain, 20 September 2012 - 10:05 PM.

[RoyenG]

Hi PSB,

i agree with the opinion to install GDU upstream of Compressor.
Instead of process wise, which is removing water from the gas at a lower pressure,
there will be also advantage in the design conditions (lower design pressure) for the GDU system.

Royen.

[PSB]

Thank you everyone for the insightful comments !

PSB

[paulhorth]

Royen,
You have not understood what Art and I have said, have you?
The lower design pressure does not necessarily lead to a lower cost for the glycol system if it is installed on the low pressure side of the compressor..

Paul

Edited by paulhorth, 21 September 2012 - 05:50 AM.

[RoyenG]

Hi Paul,

thank you for the correction,
i understand what you and Art said from the solubility and water content side that affected by operating pressure.
yes agree for for the lower pressure that material with certain thickness still can handle, but in my opinion, the cost will be affected if the material thickness have to be increased due to the pressure does not low enough.

Thanks,
Royen

[Fr3dd]

Well, paulhorth and Mr. Montemayor have presented a completely different point of view and RoyenG shares mine. I think this will be decided by the experience. As I warned in my reply, I have no experience in this kind of systems and my comments were strictly based in process engineering basic principles.

Now, paulworth and Mr. Montemayor have experience in the design and operation of this kind of systems and both have solid arguments to support their position. If it's commonly done and it works, it must be the correct way to do it.

It's always nice to learn from other people points of view.

Regards,

[Pilesar]

The selection of high pressure gas treatment over lower
pressure treatment may not be immediately intuitive. Higher
pressure vessels are thicker skinned, but have smaller
volumes and the difference in the overall vessel weight may
not be significant. Fewer sheets of steel are needed so weld
lengths will be shorter. Smaller diameter heads are
required. High pressure vapor piping is smaller diameter due
to lower volumes. Vessel nozzles are smaller.

In the field, smaller vessels require smaller foundations
and perhaps less overall plant footprint. Dehydrating after
the compressor allows some water to be condensed and
mechanically removed from the design load to the chemical
system. It is this last point that tips the scale. Why use
chemicals to remove water that you can just drain away with
a valve on a knockout drum?

The proof is in the economic analyses. Others in similar
situations have analyzed the costs and chosen to dehydrate
after the compressor. If your situation is different, a
fundamental economic evaluation will reveal it.

Edited by Pilesar, 27 September 2012 - 11:44 AM.

[Art Montemayor]

Fr3dd:

If I have learned anything in 52 years doing engineering, it is that when engineers disagree it is not about who is right and who is wrong; it is all supposed to be about what is the best, correct, and safe way to resolve the problem at hand. We all learn by being taught or acquiring the experience; we are not born with it.

I started getting involved in TEG Dehydration when I worked for BS&B (Black, Sivalls & Bryson) in 1973, a firm that was prominent in the application. I worked several TEG projects – all of them involving TEG dehydration of nominal 100 barg natural gas. Some of the projects were on land, others offshore. One offshore project took me to Lake Maracaibo where I started up two units for Meneven on one platform. These units were for gas lift application and I was requested to remain in Venezuela for a month to give TEG seminars on the operating units. Since then, practically all the applications I have worked on have involved the same nominal pressure(s). Lately, I’ve seen 70, 200, and 900 MMScfd of natural gas treated with TEG at nominal 100 barg. All of these capacities were for offshore platforms and the 900 MMScfd required a 3” wall thickness clad TEG contactor. These are very heavy pressure vessels that normally use structured packing. If you are aware of offshore platform characteristics, you will know that every square meter of platform area is very expensive as well as the total weight it must support. Every square meter and kilogram of weight on a platform must be justified economically. From experience, I know for a fact that the above TEG contactors were not optimized for a design working pressure standpoint. The operating pressure was selected due to previous experience and optimization exercises. It is an industry accepted fact that TEG contactors at these working conditions are suited for the desired effect – inspite of what appears to be a very heavy and bulky design. In other words, the TEG dehydrating efficiency at the higher pressure overcomes the more expensive and heavy equipment.

One word of caution in accepting these facts: do not assume that even higher pressures are more favorable in TEG dehydration. The process is already at the supercritical fluid state and going deeper into this phase can cause process problems. Supercritical fluids (SCFs) are reknown diluents: they can dissolve a lot of other substances and are used for that purpose. I suspect that at higher pressures the SCF natural gas can dissolve the TEG and make any downstream separation very difficult. But I have no evidence that backs this up.

We all continue to learn.....