6 replies to this topic

[apeksha2014]

In a lift gas assisted oil and gas field, how are the compressors placed in the compressor station. Are export gas and lift gas compressed to different pressures? In case they are compressed to different pressures, which of these is generally higher and is it done in multiple/two stages by withdrawing the corresponding gas after the first stage of compression? 

[Art Montemayor]

Gas lift is an artificial-lift method in which gas is injected into the bottom of an oil well’s production tubing in order to reduce the hydrostatic pressure of the fluid column at the bottom of the production tubing.  The resulting reduction in bottomhole pressure allows the reservoir liquids to enter the wellbore at a higher flow rate.  The high pressure injection gas is typically conveyed down the tubing-casing annulus and enters the production train through a series of gas-lift valves.  The gas-lift valve position, operating pressures and gas injection rate are determined by specific well conditions.   In your case, the amount of gas pressure required to achieve the gas lift is determined by the well characteristics.  Should you employ sales gas to do the gas lift?  Well, that depends on the pressure of the sales gas and the well's pressure requirements.  It is case-specific.

 

Refer to:  http://www.rigzone.c...t_id=315&c_id=4

[Bobby Strain]

There is no generalization. You must design the sytem to meet delivery pressure for both.

 

Bobby

[apeksha2014]

Thankyou Art and Bobby. I understand the idea of artificial lift gas technique. In the case I am working on, I am using a part of the sales gas for lift purpose.And the fraction of sales gas to be used for lift purpose is a variable (dependent on other factors as there are many wells on the well pad).  Also, the lift gas is required at a pressure of 400 bar whereas from what I found on net, the sales gas pressures generally do not extend 300 bar. In this case which option would be better, to have a variable split of formation gas and send two substreams(lift gas and export gas) for compression or to compress the formation gas upto export gas pressure following the withdrawal of required amount of export gas and then compress the lift gas in the second stage?

[Art Montemayor]

apeksha2014:

 

From the manner in which you presented your query I presumed you did not understand how an artificial-lift method works and why.  Now that you follow it up with more information, I still have the same impression.  Are you dealing with a real-life application or is your query conceptual?  The reason I ask is:

• 400 barg of pressure (5,800 psig) is a rather high gas pressure.  This is beyond the average of 1,500 – 2,000 psig (100 – 150 barg) usually applied.  I presume these wells are exceptional.
• Artificial lift – gas lift in this case – is used to lift liquid crude.  By itself, it doesn’t produce gas.  In order to have production gas for lifting applications you must have a relatively high GOR (gas-to-oil ratio) downstream of your wellhead, in the separators, in order to have the option of selling some of the excess gas that is not used for lifting (presuming you are using gas engines to drive your compressors.
• You require gas compressors to obtain the high gas lifting pressure required because the produced gas is at a relatively low pressure after going through the separators.
• And that is what we are referring to: each individual case requires a detailed study and evaluation of the available gas for lifting, at what pressure, and what is produced for sales.

 In other words, you have to determine your gas consumption at the wellhead and the amount of gas available for sale.  You also have to determine the sales pressure required as well as the lifting pressure.  You have to compress the portion of separator gas that you need for lifting.  That is a priority because without that requirement being met, you can’t produce anything – gas or liquids.  Once you comply with that requirement, you can either sell any excess gas or use it for reservoir pressure maintenance.  It depends on the type and quality of wells you have and the reservoir.  Generally, I would employ a secondary compression and dehydrating unit to generate the sales gas independently, according to excess gas availability.  Don’t forget that you have to dehydrate both the lift and the sales gas streams.

 

This is, I believe, essentially what Bobby has stated also.

[PingPong]

apeksha2014, you need to know the actual requirements for your specific project.

You cannot simply take some "typical" delivery pressures for lift gas and sales gas from the internet.

 

Having said that: in general, the best design is that with the least number of pieces of equipment, because that gives the lowest investment cost (economy of scale), lowest operating and maintenance cost, lowest energy consumption (big equipment has better efficiency than multiple small equipments).

 

In this case that most likely means: one multistage compressor with one driver, and the gas with the lowest delivery pressure taken from one of the interstages, and the last stage(s) further compress the gas with the highest delivery pressure requirement.

 

The total number of stages required depends on the pressure ratio between compressor suction and last stage discharge, and could be much more than two stages.

 

EDIT; I now see that Art just posted a reaction while I was writing this one.

Edited by PingPong, 23 May 2014 - 06:24 AM.

[apeksha2014]

Thankyou Art and PingPong for your insight into the topic. Now, I understand that the pressures and the compressors/dehydration unit setup is case - specific and as long as my design is practicle and would supplement the process requirement, I could go with it. 

 

Art, you said that typically 100-150 bar gas  pressures are used. In my case, I would want the lift gas to be at 280 bar ( for all the wells to cross the maxima on the gas lift performance curve,ie, GLPC).I havenot found relevant material suggesting what these pressures could go upto. Do you think compressing it upto 280 bar is too ambiguous?