Compressor Selection 3

[EmmanuelTop]

I'm looking forward to hear useful tips on how to select proper compressor type for the production gas booster compression facility (depletion compressor). The machine is to take gas at 8 barg suction pressure in 2015, suction presssure will be gradually reduced towards the year 2025 when it should reach final 3 barg. Discharge pressure is 15 barg, always.

For the same period, suction volume changes from 6,600 ACTm3/h in 2015 to 3,200 ACTm3/h in 2025 with further flow decline afterward. Power requirements correspond to 1,600 kW in 2015 and 900kW in 2025, and further down towards 300kW as we move towards 2040.

The gas compressed is essentially pure Methane. As for any production stream, we do expect certain amount of solids in gas.

Can anybody provide us with some hints on which machine (and perhaps configuration) would be the best for this application? We can consider any kind of compressor drivers (electric motor, turbine, gas engine), there are no limitations with regards to that.

Thank you

http://antwrp.gsfc.nasa.gov/apod/astropix.html

 

[BigInch]

A couple of rental units.

What would you be doing, if you knew that you could not fail?

 

[zdas04]

No recip or centrifugal machine will be there for the entire time. Recips want suction pressure (in absolute units) to be +/-5% of design conditions. Centrifugals are about half that range.

I would look at a process oil-flooded screw (as opposed to an air-derivative). Frick, Howden, Kobelco, MyCom, and Ariel would all serve well in this application. I'm not going to try to convert your actual units to standard units for compressor sizing (only air compressors report capacity in actual units, process compressors use either volume at standard conditions or mass units, and methane is typically reported in std volume/day).

David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com

"Belief" is the acceptance of an hypotheses in the absence of data.
"Prejudice" is having an opinion not supported by the preponderance of the data.
"Knowledge" is only found through the accumulation and analysis of data.

 

[Montemayor]

Emmanueltop:

I fully agree with David; the initial volume is in the neighborhood of a very large recip and although you can vary the capacity with a gas engine - as was always the case in the good ole days of USA pipeline compressor stations, you are going to have to dedicate a booster as the suction starts to drop - or invest in a "dead" 1st stage initially when the suction is at its highest. I wouldn't advise that; it starts to get economically inefficient in idle capital monies and the machines are rather big.

The centrifugal is cursed from the start when you begin to loose suction pressure and trying to vary capacity. It would normally be the machine of choice - if capacity and suction conditions were constant.

David's recommendation of an oil-flooded screw is a practical, quick, and versatile method of meeting the varying suction conditions because:

1) It meets the pressure range very nicely; oil-flooded screws have been in 20 barg service for many years now and have proven their application at this level;
2) You can install VFDs on several machines and have not only versatility, but also potential backup machines; with this capacity range you will need several machines operating initially. As time goes by, you can retire or sustain one or two as back ups. The money invested is not entirely wasted - especially since the capacity of each machine can be selected to fit a common application in another, local installation.
3) I think you will discover that screw compressors will have a better availability and a better bidding competitive situation than other types. the delivery should be much better than a recip and even a centrifugal - especially if gas turbine driven.

 

[bcs5274]

oil flooded screw with electric drive plc based vfd would be ideal i would say also

 

[EmmanuelTop]

Thank you for your replies.

You are right, due to nature of reservoir depletion we will probably go for configuration with several machines in parallel and decommission them as the production declines by years.

Are the oil-flooded screws considered reliable in a fairly dirty production field environment? Or, to put the same question in another way, what kind/level of production stream separation and suction gas pre-treatment we need to provide in order to have these machines running without risk of damage? Is there something particularly required for oil-flooded screws vs. other types of compressors?

Can gas turbine be employed for smaller machines, requiring e.g. 400kW power per machine?

http://antwrp.gsfc.nasa.gov/apod/astropix.html

 

[zdas04]

Gas turbines turn at a very high speed. The only compressors that tolerate that speed effectively are centrifugal, but they have a really narrow suction pressure range.

There is no way to get any assurance that any machine will run "without risk of damage". I know guys who could cut themselves with a rubber hammer. In my experience, with a tiny bit of FOCUSED training, oil-flooded screws are as close to idiot proof as any equipment I've ever deployed.

I think that the first hp any well sees should be an oil-flooded screw. They are really tolerant of changing conditions and rough fluids. The big issue is compatibility of fluids. If you have a significant amount of C3+ in your stream, you want to send a gas analysis to the compressor manufacturer and use their recommendation for oil. It will not be the least expensive oil, but compared to oil contamination it will be the cheapest life cycle expenditure.

If you are concerned about water, oil, coal fines, and frac sand then all you need is a 2-phase separator (I prefer vertical) with a mist extractor to get the gas clean enough for a screw. You should not really be worried all that much about a bit of liquid getting to the process since it is "oil flooded".

Oil flooded screws are rough, rugged, and reliable if you do two things: (1) make certain that the oil is compatible with your fluids; and (2) keep the discharge temperature in the 205-215F range. That is it. Do those two things and these are sweet running machines that give a bunch of service for very little care and feeding.


David Simpson, PE
MuleShoe Engineering

"Belief" is the acceptance of an hypotheses in the absence of data.
"Prejudice" is having an opinion not supported by the preponderance of the data.
"Knowledge" is only found through the accumulation and analysis of data.

 

[Montemayor]

Emmanueltop:

If there is reason for a concern on local cleanliness of the natural gas – or if you are forced to confront possible slugs of liquids (and worse of all, sand) – then, the application of conservatively designed gas separation units is a wise one. Apart from the production line slug catchers, I would recommend horizontal vapor-liquid separators, followed up with “polishing” vertical separators with internal mesh to “filter” out droplets. This type of treatment is analogous to what is done in small gas fields where horizontal “filter” separators combined with a horizontal “barrel” underneath are meant to do in trying to produce a relatively clean and manageable natural gas product. In your case, I would presume your flow rates are rather larger than the usual – and suspiciously variable in quality. Ergo, the horizontal vessel application up front to take care of the bulk of any liquid or solid contaminants with a capacitance factor to boot, and a conservative, vertical polishing separator to ensure any contaminant has the probability of being separated at that point. If solids or debris are a possibility, then the horizontal separators are the place to install internal de-sanding devices to at least have a chance to keep them in service for longer durations. In the case of getting bombarded with a sand (or solids) problem in a natural gas field, it is best to evaluate that NOW and not later after it occurs. The cost of fabricating 8 barg vessels locally (for example, in Latin America) is not a factor that would bother me. This level of design, fabrication, and installation is fairly common and should be an easy task for a local fabrication shop. Internals – such as mesh filters and desanding sprays and controls may have to be imported – but that is about it.

If the gas is separated as described above, you will have a protected and predictable oil-flooded screw compressor operation. The cleanliness factor is not, in my opinion, a trade off presented by the screw compressor. The engineering and capital cost of cleaning up the gas is common to any other type of compressor evaluated for this service.

I hope this experience helps.

 

[rotatingequipengr]

Emmanueltop:

I fully agree with David's comments above and that an oil-flooded screw compressor is likely your best solution for the application. Given the nature of the process (declining suction pressure and flow-rate) a properly designed oil-flooded screw compressor package can likely meet the full needs of your design with a single compressor.

In fact, if there is one point that I may add to the conversation it is that the oil-flooded screw compressor should be able to meet your varying capcity requirements over the life-time of the application with a simple fixed speed induction motor installation (no VFD necessary). The oil-flooded screw compressor utilizes an internal slide valve providing built-in turn down capability, typically down to approximately 20% of design capacity. This can greatly reduce your capital cost for the installation and still provide cost savings for reduced power consumption later on in the life of the compressor. At the very least it would be worthwhile to consider this power savings versus that which you would receive with the VFD operation. Any reputable packager/vendor should be able to provide you the (linear) turn down curve with varying suction pressure as well as flow-rate allowing you to determine the projected costs.

Good luck with your application!

 

[EmmanuelTop]

Big hanks to everybody for the replies!

Best regards

http://antwrp.gsfc.nasa.gov/apod/astropix.html

 

[dcasto]

I'd install 1 stage 4 cylinder compressor that can handle the rod load all the way to 3 ratios. Then at 3 ratios you would split the machine into 3 cylinders in 1 st stage and 1 on second stage. That would allow suction press down to 1 barg.