Approach to size separator + heater treater for new wellsite facility

[aegis4048]

Hi, I'm tasked with sizing a separator + heater treater for a new well. The plan is to come up with some flow predictions, and give those info to manufacturers to recommend us vessel designs. But I'm not sure how to tackle the volume prediction...

Here's the given information
1) Wellhead -> 100~200 psig normal operating P. 2-ph separator -> ~30 psig 3-phase separator -> water & oil atmospheric tanks.
2) I have offset produced oil & water rate, and sales meter gas rate. The oil and water volumes are measured from the outlet of the atmospheric tanks. The gas volume is measured at a sales meter that has combined gas from both 2-ph separator, and the 3-ph heater.
3) I have gas composition off the 2-ph separator.
4) I have API gravity of oil at the tank
5) I have access to a process simulation software (Promax) and I know how to do flash calculation

A. Given these information, how would you go about predicting liquid & flash gas volumes at 2-ph separator, heater, and the tanks?

I know that if I can get the pressurized liquid sample analysis from the 2-ph separator, and get approximate operating conditions (T & P) of the vessels, I can easily calculate flash volumes and liquid rates using the process sim software. But there's a good chance that I won't be able to obtain the pressurized liquid sample analysis from the separator.

B. If there's no liquid sample analysis, how do ppl normally size the separators and treaters?

C. If I predict the normal flowrate to be, say 100 bbl/d 50 MCF/d, how much extra room should I give it when sizing?

 

[1503-44]

1) Take your gas flow rate at measured P & T conditions and convert to standard gas flow rate at STP.
Do flash if you see potential for different results, but if you have measured values, why would those be different?
Failing that,
2) Take your predicted standard flows and convert to any specific vessel, or any P&T condition you are interested in.

20-25%-30% But that is highly dependent on oil API and often depends more on your well development and optimum production rate is now and in future, or your rework plans then what the exact composition of any one gas stream might be at any given time. What flow rate you have today may not be tomorrow's.

What's your oil API? 10 and there's not much potential for flash. 70 and you will flash a lot of it.


--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."

 

[shvet]

maybe this will help
API 14e

http://www.bobby-strain-group.com/Default.aspx

https://epcon.com/api-data-book/

https://checalc.com/calc/horizsep.html

 

[aegis4048]

@shvet

I have access to a commercial sizing software, so those are not what I'm looking for. I'm more interested in how ppl predict flash volume & liquid volume given only those limited data that I listed. Equipment sizing must have flowrate predictions, rn I'm not too sure how to do that

 

[shvet]

There is no way. Actual flowrates and transport properties of GLL phases are required for equipment sizing.
Software is able to make some predictions based on indirect parameters. In such case results have to have application limits. Did you look into the ProMax manual?

 

[1503-44]

https://photos.app.goo.gl/ZCZ3SVqTXYMDH9DH9

--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."