6 replies to this topic

[Erwin APRIANDI]

Hii.. All,

I really need a help here...

Right Now we are in progress of making a conceptual study for gas treatment facility

the inlet vapour gas going to the test separator will be design at 160 MMSCFD

the inlet well fluid is a sour stream with inlet mole composition of CO2 at 0.2750 and H2S at 0.0100

the gas are being treat to meet the sales gas specification as follow :

H2S Content 80 ppmv MAX
CO2 Content 0.1500 MAX
GHV min 925 btu/scf
Delivery Pressure 300 psig

I really need some input about any lisence technology that you all may known
Since the study will only gonna take 3 month from this moment

We've been currently chosing so0me process such as amine treatment, and claus process for the acid gas treatment. but we still haven't know what is the limitation of this technology

Thank you...

Best Regards,

Erwin A.

[JoeWong]

Erwin,

...the inlet vapour gas going to the test separator will be design at 160 MMSCFD

Quick comment. Are you sure your test separator to be designed 160 MMSCFD. This is BIG !.
What is your flowline size ?

the inlet well fluid is a sour stream with inlet mole composition of CO2 at 0.2750 and H2S at 0.0100

Just for curiosity, can you advise your field name ?

the gas are being treat to meet the sales gas specification as follow :

H2S Content 80 ppmv MAX
CO2 Content 0.1500 MAX
GHV min 925 btu/scf
Delivery Pressure 300 psig

Delivery pressure seem low. What's the downstream facilities ?

I really need some input about any lisence technology that you all may known
Since the study will only gonna take 3 month from this moment

We've been currently chosing so0me process such as amine treatment, and claus process for the acid gas treatment. but we still haven't know what is the limitation of this technology

You may consider Mole Sieve with membrane technology from UOP, NATCO, etc. for dehydration and CO2 & H2S removal.

You may think of CO2 reinjection for CO2 & H2S handling.


HTH
JoeWong

[Erwin APRIANDI]

>Delivery pressure seem low. What's the downstream facilities ?

The WH SIP is 3100 Psig with Temp 270 F, and we'll in the scenario of opening down stream of the choke valve at 1000 psig in order to have an optimum operating condition of the amine system.

but, I still haven't found any literature which state the Optimum operating condition of the amine system. For 900 Psig I have a recommendation from a friend of mine. Is it the right recommendation???

>Quick comment. Are you sure your test separator to be designed 160 MMSCFD. This is BIG !.
What is your flowline size ?

and yes it is a 160 MMSCFD design separator but for the flowline we still ingoing for the study of hrydraulic pressure drop using PIPESIM.

>Just for curiosity, can you advise your field name ?

For the field name I think I have to classified it for now, Just for slight info it is a field located in Indonesia

So please I really need the contact info for any licensor...

Regards,

Erwin Apriandi

[JoeWong]

The WH SIP is 3100 Psig with Temp 270 F, and we'll in the scenario of opening down stream of the choke valve at 1000 psig in order to have an optimum operating condition of the amine system.

but, I still haven't found any literature which state the Optimum operating condition of the amine system. For 900 Psig I have a recommendation from a friend of mine. Is it the right recommendation???

In general, higher pressure ==> better absorption
lower temperature ==> better absorption
However, shall always take extra care that low temperature potentially result HC condensed and result serious foaming in Amine system

Ask your friend, why 900 Psig, any specific reason.

You may consider activated Amine e.g. BASF aMDEA, pretty stabil and small installation compare to ordinary amine.

yes it is a 160 MMSCFD design separator but for the flowline we still ingoing for the study of hrydraulic pressure drop using PIPESIM.

A bit surprise. Isn't it you have production forecast and flowline / test sep production rate can be fixed base on quantity of wellhead completion. Eventhough you have excess pressure, the velocity may be excessive and may be exceeded the erosion velocity...anyway too little info to judge. Just feel that a bit high.

So please I really need the contact info for any licensor...

Are you refering to UOP MS + membrane or BASF aMDEA or....?

If ordinary Amine e.g. MEA, DEA, MDEA, etc, i don't think there are any licensor. EPC firm e.g. FW, FD, TECHNIP, WORLEY PARSON, CHIYODA, TOYO, etc may be able to assist you.

JoeWong

[Art Montemayor]

Erwin:

Forget about your field's name - just give us the basic data required to generate some processes that will get you where you want to go.

You don't tell us the basic data that all Chemical Engineers require: a PFD and a composition of what is going in and what you expect out. You can easily do this in Excel. In fact, I'll bet you my year's salary that you (or somebody on your team) has already done it and is working with it. That's why you didn't tell us the inlet pressure to the Field Separator and your field heater - if you are using one or several. What we need to know is what is the process conditions entering the process unit you envision - complete with compositions.

Tell us what you want to do with the Sulfur and the CO₂ that you intend to separate from the Field Gas. YOU (or your company) have to identify that, not us and much less the licensor for whatever process you may like. Those are basic decisions that must have been made already -- and I would bet that you know them also, but are not telling us. Why force us to guess and speculate about what you can and can't do with the Sulfur and CO₂? We all know what can be (& is conventionally) done with these compounds. Tell us so that we can recommend a licensor. If you intend to vent H₂S, that is your perogative. But if you intend to convert all the H₂S to elemental Sulfur and sell/export it as such, then you need a Claus Plant. And don't tell us that "CO₂ Content 0.1500 MAX". What is that supposed to mean in specific Chemical Engineering logic? Do you mean ppm? If so, in what terms? I realize that you are only doing a conceptual study, but picking your terms as you go along is a bit too much.

I believe all you are contemplating is an Amine process (MEA or MDEA), a Claus Plant, and a TEG process. These would be divided up into trains. Am I right? The problem is what to do with the damn sulfur and the CO₂. Your company directors (& your Board) will have more to say about that than us - and probably already have stated so.

Are you going to separate your C3+ heavies by a cryogenic processing unit? You haven't told us this either. I seriously doubt you would propose a 160 MMScfd separator. I can see 3- 60 MM Scfd units in the field. Without the flows and pressures, you can't estimate the inlet pipe sizes. The pipe size will play a big role in fixing the size of the units - availability, constructibility, and flexibility. I think you already know this and have picked the pipe sizes and the separator size(s). If so, why not share this? I also expect this installation to be onshore and not on a floating production & storage vessel off the Indonesian Straits.

Await your reply with basic data.

[pawan]

If your gas is non-hydrocarbons then Use GENOSORB process else go for MDEA process. Both are commercially available & very successful in handling large volume systems.

[Erwin APRIANDI]

>"Forget about your field's name - just give us the basic data required to generate some processes that will get you where you want to go."

Dear Art enclosed is the wellfluid condition of Alur Siwah Field in North Sumatera

>"You don't tell us the basic data that all Chemical Engineers require: a PFD and a composition of what is going in and what you expect out. You can easily do this in Excel. In fact, I'll bet you my year's salary that you (or somebody on your team) has already done it and is working with it. That's why you didn't tell us the inlet pressure to the Field Separator and your field heater - if you are using one or several. What we need to know is what is the process conditions entering the process unit you envision - complete with compositions."

The PFD is still in process since this stage of project is still in pre-FEED stage or conceptual design so every option is still open.

>"Tell us what you want to do with the Sulfur and the CO₂ that you intend to separate from the Field Gas. YOU (or your company) have to identify that, not us and much less the licensor for whatever process you may like. Those are basic decisions that must have been made already -- and I would bet that you know them also, but are not telling us. Why force us to guess and speculate about what you can and can't do with the Sulfur and CO₂? We all know what can be (& is conventionally) done with these compounds. Tell us so that we can recommend a licensor. If you intend to vent H₂S, that is your perogative. But if you intend to convert all the H₂S to elemental Sulfur and sell/export it as such, then you need a Claus Plant. And don't tell us that "CO₂ Content 0.1500 MAX". What is that supposed to mean in specific Chemical Engineering logic? Do you mean ppm? If so, in what terms? I realize that you are only doing a conceptual study, but picking your terms as you go along is a bit too much."

The outlet gas from the plant should have a GHV of 925 Btu/ft3 which by Hysys simulation this value is gain with the amount of CO2 of 12%mole, at first I'm mentioning 15%mole this is a correction.

>"I believe all you are contemplating is an Amine process (MEA or MDEA), a Claus Plant, and a TEG process. These would be divided up into trains. Am I right? The problem is what to do with the damn sulfur and the CO₂. Your company directors (& your Board) will have more to say about that than us - and probably already have stated so."

We have pre eliminary simulating a process of Amine & Mebrane for the CO2 and H2S removal, TEG fir dehydration, and Turbo Expander & Mechanical Refrigeration (C3) in Hysys the purpose of our study.

>"Are you going to separate your C3+ heavies by a cryogenic processing unit? You haven't told us this either. I seriously doubt you would propose a 160 MMScfd separator. I can see 3- 60 MM Scfd units in the field. Without the flows and pressures, you can't estimate the inlet pipe sizes. The pipe size will play a big role in fixing the size of the units - availability, constructibility, and flexibility. I think you already know this and have picked the pipe sizes and the separator size(s). If so, why not share this? I also expect this installation to be onshore and not on a floating production & storage vessel off the Indonesian Straits."

And the facilities does going to be located in Onshore in North Sumatera

>"Await your reply with basic data."

I hope this enough for know... Please inform for any further question

Best Regards...

Erwin Apriandi

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