Choke modeling using OLGA 1

[ginsoakedboy]

I am trying to simulate the J-T cooling at Choke valve during Subsea tree startup using OLGA. I am not a petroleum engineer, so please be kind. Among a slew of questions I need answered are:

1. Is OLGA the right tool to perform a transient simulation of Choke opening operation?

2. What is critical flow in the context of a Choke Valve? Does criticality of flow affect J-T cooling (or heating)? Is it related to the inversion temperature?

3. I am trying to find typical values of parameters so my calculations will be fairly representative of the different field conditions. Will the black oil model be a good approximation?

4. Generally speaking, are production fluids with high proportion of oil are more susceptible to J-T cooling? Or, the ones with higher gas percentage?

5. During a well startup, what might be "maximum ?P" across the Choke? I imagine the maximum ?P is experienced immediately after the Choke is cracked open.

6. During full blown production, what may the ?P across the Choke?

Thank you all in advance,
S.

 

[EngAbdelkader]

Hi skywalker, as I understand from your post, by J-T you mean Joule Thomson effect after choke, isn't it?

Well as far as I know and believe you me, I don't know a lot! the Joule Thomson effect concerns mainly gases and not liquids and the best way to figure out the phenomenon is to take a look at the thermodynamic charts of the fluid you are studying lets say that you want to know the effect on a stream of gas that contains mainly methane (C1) so you can take a look at the charts provided in the GPSA handbook for example.

Now if you have a question on how to use the charts, let's take a simple example, take the P-H chart (P for pressure and H for enthalpy) draw a vertical line (constant enthalpy) from the point P1 that represents the pressure before choke (be aware that this point should coincide also with the temperature of your fluid T1) , to the point P2 that represents the pressure after choke obviously, where the last point crosses the temperature curves is your final temperature (T2) .
I hope this answered a part of your question. Regarding the simulation, I am more used to run simulations on Aspen hysys even if I am not an expert in it, I think it'll work for you.

Good luck and remember, never take someone else advise as a rule! confirm what I said asking more people as I am not an expert!

 

[Malkara]

Hi to everybody,

I need some information about petroleum production from oil water contact. How % water and salinity of produced oil changes with time. In such situation what shold be the main production strategy ?

And, one more question! Does anybody use a digital equipment for oil level measurement without strip chart and 11.0 diverter.

Thanks for your attention...

 

[EngAbdelkader]

Sorry Malkara I don't understand your question!

the oil water contact (owc) is the zone in the reservoir that separates the water from oil, sometimes it's called "water table" and as you know (and I guess you know it better than me!) this zone is not a clear line between these two zones! it's a zone in itself as it's an emulsion like zone!

as far as I know we produce from the oil zone that is called pay zone, neither from the owc nor from water obviously (unless you want to produce water from your oil field, but than you'll be in big trouble with your field manager!)

that is for the oil water contact, than let's speak a little about produced water! as you know you'll have always water with you oil, the technical word to define this water is the "water cut" that is in the beginning of the production is low sometimes as low as 1 to 2% than obviously increases year after year! this percentage can increase dramatically if you have what we call "water conning" phenomenon.

for the salinity it's different from one field to another and depends on the geological history of the field.

for the oil level I think you mean the pay zone so it's done after running a logging job in the wells and in this case the logging tool is based on the resistivity of the fluid in front of the tool (salt water has high conductivity so less resistive which is not the case of the oil that has a very low conductivity and can be considered as non conductor fluir)

for the production strategy, don't worry you'll be a team managing this issue! because it's related to the productivity of your field, the Productivity index, economics, reservoir issue, and much more disciplines!

 

[ginsoakedboy]

Can anyone answer the original question posed in this post? thanks.

 

[EngAbdelkader]

skywalker09,
I have already tried to answer you! look at my previous post here (dated 16th of may) and sorry if I use your thread to answer also Malkara that posted a question that didn't have anything to do with your post!

I will add that the critical flow in the context of the choke valve is related to the pressure drop so the differential pressure between the upstream and downstream the choke pressures.
The best definition I found is :
Whenever pressure downstream of a choke is less than the critical pressure, the flow rate of a gas through the choke will be a constant that is dependent upon the upstream pressure and the speed of sound.
The critical pressure is the pressure downstream the choke and generally it is about 1/2 of the upstream pressure.

if upstream the choke the pressure is about 80 bar for instance and > or = 40 bar downstream the choke, you have a critical flow condition! that means that you'll have a reverse effect of the choke.
I mean by reverse that in the normal case your upstream pressure should govern the downstream one through the choke, this condition is no more verified under a critical flow (so in this case it's your downstream pressure that can affect the upstream choke pressure)

and finally when we speak about black oil we SPEAK about oil (liquid) and as I explained in my previous post here (16th of may) the Joule Thomson effect concerns the gases!!!

I would add that all your questions are welcome I am not a petroleum engineer but a mechanical one! but working in the oil business I've learned a bit and I try to share it doing my best!

P.S: you can post the data you have so perhaps I can take a look on it and try to help you figure out a solution!

 

[DuhonGATE]

Skywalker09,

I think I can help with your questions:
1. Olga is a good tool for studying JT cooling assuming an appropriate thermo model has been built into the model you are running. Consult one of the flow assurance firms if you have questions about building the thermo model.
2. Critical flow occurs in gas flow at a pressure drop of about half the inlet pressure. Critical flow also occurs in two phase (liquid/vapor) flow. Sachdeva (SPE15657) provides a correlation for the determining the critical flow boudary of two phase flow. Critical flow should not impact the JT cooling except that the pressure drop through the choke does not impact downstream pressure. The amount of JT cooling will be a function of the inlet pressure and downstream piping pressure which will be lower than the pressure immediately downstream of the choke.
3. Can't help you here. I don't know if any black oil models address JT cooling. I'd be interested in hearing back from you if you've learned something about this.
4. I think that gases are more susceptible to JT cooling, but not sure about the accuracy of that at very high pressures. I also believe that liquids are more susceptible to JT heating. At very high pressures (say above 4000 psig) I think you are more likely to have JT heating than JT cooling.
5. You are correct that the maximum DP would usually occur at the point when you first crack open the choke. But that will depend on how you start up and what the downstream condisiton are over time. In subsea startups it would not be uncommon to find thousands of psi of pressure difference between SITP and flowline pressure at ambient conditions. It might be advisable/necessary to pressurise the flowline prior to opening the choke to minize the initial DP for choke protection and completion protection.
6. You may not have any choice about this. If the choke is your only control point then the pressure drop will be what it is. If you have options such as a subsea choke and an arrival choke it is common to try to take significant pressure drop on the surface so as to protect the subsea choke. For information of choke longevity as a funciton of DP I would talk to the choke manufacturer. There are rules of thumb out there such as keeping the DP below 1000 psig; I don't know how valid that is.

Hope that is useful and not too late.

DuhonGATE