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Gas Hydrate Inhibitor Injection Calculations




Gas Hydrate Inhibitor Injection Calculations Gas Hydrate Inhibitor Injection has been discussed previously on "Cheresources" in several posts. Besides the fact that the "Hydrate Utility" in HYSYS can calculate inhibitor injection rates, there are other methods programmable in a simple excel sheet that can be utilized to provide fairly accurate inhibitor injection rates. Equations provided by "Hammerschmidt" and "Nielsen-Bucklin" can provide good estimates for hydrate inhibitor rates and my endeavour to find alternatives to sophisticated simulation software such as HYSYS has led to the development of several excel spreadsheets related to equipment sizing and other calculations in the oil & gas field. On such effort on my part was dedicated to prepare a comprehensive calculation sheet for hydrate inhibitor injection using both the "Hammerschmidt" and "Nielsen-Bucklin" method. Since the estimation of water content in natural gas is an essential part of this calculation I had to integrate the water content calculation from the water content spreadsheet I had posted on "Cheresources" at:

http://www.cheresour...of-natural-gas/

Let us move on to the actual background and content of hydrate inhibitor injection and the related equations

Commonly used hydrate inhibitors are Methanol & Monoethylene Glycol (MEG) for depressing the hydrate formation temperature. The "Hammerschmidt" equation gives the hydrate depression temperature as a function of the concentration (weight fraction) of the inhibitor in the final water phase & the molecular weight of the inhibitor. The actual injection flow rate is a function of the water content which condenses in the pipeline from the source pressure & temperature conditions to the destination pressure & temperature conditions. For a unboosted pipeline, this essentially means a drop in pressure & temperature.

Hammerschmidt Equation:

d = K*w / (1.8*MWinhib*(1-w))

where:
d = depression of the water dew point or gas hydrate freezing point, deg C
K = constant, dimensionless, Methanol = 2335; Monoethylene Glycol = 2700
w = mass fraction of inhibitor in final water phase
MWinhib = MW of inhibitor, Methanol = 32, Monoethylene Glycol = 62

Note:
The above equation is only applicable upto 25% by weight for Methanol & 70% for MEG in final water phase
i.e. w <= 0.25 for MeOH and w<= 0.7 for MEG

Inputs Required to set up the spreadsheet calculation:

1. Gas Flow Rate, Sm3/day
2. Upstream Gas Pressure, kPa (abs)
3. Upstream Gas Temperature, deg C
4. Downstream Gas Pressure, kPa (abs)
5. Downstream Gas Temperature, deg C
6. Hydrate formation temperature, deg C (from commercial simulation software or from the spreadsheet posted by me in my blog entry "Determining Hydrate Formation Temperature")
7. Inhibitor Used (Choose between Methanol or MEG)
8. % MEG used (Note: Methanol is generally injected as 100% by mass as Methanol whereas MEG is generally injected as water-based solution of <= 90% by mass)

Outputs obtained from Spreadsheet Calculation:

1. Upstream water Content, mg / Sm3
2. Downstream water content, mg / Sm3
3. Water Condensed, kg/day
4. "d" = Hydrate formation temperature - Downstream Gas temperature
5. "w" by solving the Hammerschmidt equation for w
6. Total qty of inhibitor = Water Condensed*w , kg/day
7. Mass rate of inhibitor in aqueous phase = Total qty of inhibitor / 1 - w, kg/day

When Methanol is used as an inhibitor, vaporization losses to the gas phase need to be considered and added. The attached figure may be used to estimate vaporization losses of MeOH to gas phase.

Another important point to note is that for "d" values greater than 13.5, the "Hammerschmidt" equation using MeOH as inhibitor is not valid since the mass fraction of MeOH in water phase increases beyond 0.25. Use the "Nielsen-Bucklin" equation for MeOH concentration >0.25 mass fraction

Nielsen-Bucklin Equation:

w = xm*32.04 / (18.015 + xm*14.025)

where:

w = mass fraction of MeOH in final water phase

xm = 1 -exp(-d/72)
where:
d = depression of the water dew point or gas hydrate freezing point, deg C (>13.5)

Vaporization losses are to be calculated as explained previously.

To conclude, hydrate inhibitor injection calculations can be set up using a spreadsheet and anybody interested can do so using the guidelines provided above. I would be more than happy if somebody sets up an excel spreadsheet and requires me to check it.

Hoping to have a lot of comments from the members of "Cheresources".

Regards,.
Ankur

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Paulo Edson Silva Junior
Nov 06 2012 10:06 PM
Hi, could you send us the spreed sheet for MEG INJECTION RATE calculatios?

Regards, Paulo (paulosilvajr@hotmail.com)

Hi, could you send us the spreed sheet for MEG INJECTION RATE calculatios?

Regards, Paulo (paulosilvajr@hotmail.com)


If I had wanted to share the spreadsheet I would have already posted it as an attachment to the blog entry and saved myself the trouble on writing about how to set-up the spreadsheet using the equations provided. As I have mentioned make your own spreadsheet and I will help in editing and making corrections..

Regards,
Ankur.

If I had wanted to share the spreadsheet I would have already posted it as an attachment to the blog entry and saved myself the trouble on writing about how to set-up the spreadsheet using the equations provided. As I have mentioned make your own spreadsheet and I will help in editing and making corrections..

Regards,
Ankur.


Hi Ankur,

May I ask you please. Could you provide a references for above presented calculations. Where can i find more details about the equations and explanations.

I will highly appreciate wheather whether you provide a book name and author

Thank you in advanced

Regards,
Alex

ankur2061, on , said:


If I had wanted to share the spreadsheet I would have already posted it as an attachment to the blog entry and saved myself the trouble on writing about how to set-up the spreadsheet using the equations provided. As I have mentioned make your own spreadsheet and I will help in editing and making corrections..

Regards,
Ankur.

Hi Ankur,

May I ask you please. Could you provide a references for above presented calculations. Where can i find more details about the equations and explanations.

I will highly appreciate wheather whether you provide a book name and author

Thank you in advanced

Regards,
Alex


Alex,

Refer Section -20, Dehydration in the GPSA Engineering Databook.

Regards,
Ankur
Hi Ankur,
I think you can share the spreadsheet. There's no harm in it.

Dear Mr Ankur,

 

I am still a student, and I really appreciate your great work,

Please keep up the good work.

 

Regards,

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hockyau.lim@gmail.com
May 07 2014 09:50 PM

Hi Ankur, 

 

The temperature used in Hammerschmidt's equation shall be positive value right? If I have a hydrate formation temperature at -54.3 degC, shall I convert it to 54.3 degC, so that I could get my 'w' below 1.0.

 

Thanks for your reply.

Hi Ankur, 

 

The temperature used in Hammerschmidt's equation shall be positive value right? If I have a hydrate formation temperature at -54.3 degC, shall I convert it to 54.3 degC, so that I could get my 'w' below 1.0.

 

Thanks for your reply.

Why would I use a hydrate inhibitor for a gas mixture whose hydrate formation temperature is -54.3°C. Hydrate formation is favored by high pressures and low temperatures. I do not know of any practical application where the natural gas is transported at  below -50°C. Hydrate inhibition would  only be required if my operating temperature is at or below the hydrate formation temperature at the corresponding operating pressure.

 

You cannot change minus sign to show positive value. As per what I have studied and understood at very low hydrate formation temperatures the Hammershmidt equation will give weird results.

 

Regards,

Ankur.

Ankur:

I have a question, 

Why the MEG is generally injected as water-based solution of <= 90% by mass?

Is there any problem if the injection have 100% MEG (without dilution)?

 

Thanks,

Ankur:

I have a question, 

Why the MEG is generally injected as water-based solution of <= 90% by mass?

Is there any problem if the injection have 100% MEG (without dilution)?

 

Thanks,

MEG mixed with water itself acts as an antifreeze agent compared to pure MEG. In a nutshell, MEG-water mixtures are more efficient in preventing hydrate ice crystal formation compared to pure MEG.

 

Regards,

Ankur.

Thanks! Ankur,

Could you please recommend me a bibliography about this point (100$% MEG injection)?

Thanks! Ankur,

Could you please recommend me a bibliography about this point (100$% MEG injection)?

Properties of glycol-water mixtures are available as open source from internet. From 60% to 90% glycol-water mixtures have freezing point below -20 degC. Pure glycol has a freezing point of -13 deg C. Thus it is obvious that it is better to use glycol-water mixture compared to 100% glycol.

 

Regards,

Ankur.

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Ayan.Zholmurzayev
Jul 20 2016 06:08 AM

Thank you Ankur,

I've tried to prepare the spreadsheet so could you please review it.

 

At the moment I'm working on coalbed methane feasibility study.

Wellhead pressure is about 200 kPa, temperature approximately 30 C, gas composition as shown in hydrate formation sheet.

 

I'll have to prepare BFD, PFD's, H&MB for the whole process could you please advice where I can find relevant information?

 

http://www.evernote....o19BteMv7gfRoU/

 

 

Best regards,

Ayan

Thank you Ankur,

I've tried to prepare the spreadsheet so could you please review it.

 

At the moment I'm working on coalbed methane feasibility study.

Wellhead pressure is about 200 kPa, temperature approximately 30 C, gas composition as shown in hydrate formation sheet.

 

I'll have to prepare BFD, PFD's, H&MB for the whole process could you please advice where I can find relevant information?

 

http://www.evernote....o19BteMv7gfRoU/

 

 

Best regards,

Ayan

Dear Ayan,

 

I have seen your excel sheet. However, I would request you to do an analysis of the problem first. If your downstream temperature is higher (in your sheet it is 5 deg C) than the hydrate formation temperature (in your sheet it is -9 deg C), then why would you require injection of any hydrate inhibitor.

 

Please understand that only when the downstream temperature is lower or equal to  the hydrate formation temperature, there will be hydrate formation.

 

The example you have used is incorrect considering the downstream temperature to be higher than the hydrate formation temperature.

 

Hydrate formation occurs at a certain combination of pressure and temperature. Hydrate formation is favored by low temperature and high pressures.

 

I am sending you a personal message with the corrected sheet which includes my comments.

 

Regards,

Ankur.

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Ayan.Zholmurzayev
Jul 20 2016 09:27 PM
Dear Ankur,
 
I'm very grateful for your feedback and comments on the spreadsheet. I really appreciate your help.
 
As I mentioned in my previous message I'm dealing with feasibility study I would say even pre-feasibility and Contract has not been signed yet. 
 
Wellhead pressure is given is about 200 kPa, few wells are under experimental (test) production at the moment with approximate well flow rate 1000 m3/day and currently, a subsurface contractor doesn't have all the required information such as total quantity of wells, wells flow rate during the commercial production, wellhead temperature etc. 
 
30 degree C at the wellhead was my guess and downstream 5 degrees C temp. before the booster compressor was my guess as well, so I just wanted to have that spreadsheet ready.
 
Best regards,
Ayan

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