Dehydration of carbon dioxide for oil field injection

[jeap]

Hi All!

We have a gas with the next approximate mole composition:
CO2 90.0%
C1 9.0%
CN 0.9%
H2S 0.1%

Pressure 80 Kg/cm2g
Temperature at gas pipeline inlet 50 ºC.


It is desired to inject this gas in an oilfield. Do you have any idea if a moisture content of 9 lb/MMscfm is convenient for this service?

I don't have any reference value for corrosion rate at this conditions or if corrosion is an important issue with that moisture content.

I assume a condition of supercritical fluid a P, T and I observe that condensation of CO2 is produced in the first 100 m of pipeline.

Other data:

Pipeline lenght 1000 m

Thanks in adevance for your help

jeap

 

[zdas04]

Without liquid water, CO2 is not corrosive. 8 lbm/MMSCF is quite a ways below 100% RH at 50C and 78 barg (I can't bring myself to talk in kg/cm^2g) so you might be safe unless the gas cools off considerably in the 1,000 m of pipe (you didn't talk about flow rates or pipe size so I couldn't even guess what your cooling potential is).

If the pipe does cool off to the point where 8 lbm/MMSCF is above 100% RH then you'll get condensation and standing water. Now you have to guess (and it is a guess) whether the water will absorb the CO2 and become acidic or basic, the activation energy for carbonate or carbonic acid is almost identical. If you can convince yourself it will form carbonate and be basic then you have no worries. If you form the acid then the pipe will disolve before your eyes.

If they were my dice I wouldn't risk it. There are some spoolable composites coming onto the market that can handle this pressure and are chemically inert. I'd look at that if your flow rate is low enough to fit into a 4-inch pipe.

David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com

Please see FAQ731-376 for tips on how to make the best use of Eng-Tips Fora.

The harder I work, the luckier I seem

 

[SJones]

http://www.gasliquids.com/papers.html

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[jeap]

Thanks for answering.

Well, I forget to give flowrate and pipeline size, because I was worried about the corrosion issue but here go complemental data:

Flowrate 600M Sm3/d and pipeline size 4" (as you figured out).

In fact after running some simulations in Hysys, I've found that condensation of CO2 and water is possible between tue first 100 m of pipeline because soil temperature at winter conditions drops to 5ºC. I considered a buried depth of 1m.


Since I assumed that no salts were present in the water.I am not sure that pH could be high enough to prevent carbonic acid formation. Both, water and gas, come from primary separation and for environmental regulations it was forbidden to release it longer so operator is in a big hurry!

By rewiewing the articles from SJones, some worries desapeared; manly those concerning to moisture concentration. Simulations showed that is possible to reach that low water content mantaining 25º at compressor suction and in some cases recirculating up to 10% of flow at summer conditions. This is a four stages compressor (2,5 to 80 Kg/cm2). From my point of view it was no necessary to use a TEG unit for dehydrating the mixture but take in to consideration a change of material before entering the third stage of the compressor where condestate is possible

However, pipeline corrosion could be possible under my considerations. Do you have any comment?

Thank you again!

 

[zdas04]

The water that can accumulate is distilled water from condensation, the pH will consistently be very close to 7.0 for many miliseconds after condensation. Nature really hates distilled water and it will start to absorb "stuff" really quickly. When it absorbs some of your trace H2S it will move towards acidic. That could create a preference to drive the CO2 reaction toward acidic, but not necessarily. If it creates some carbonate then it will move towards basic. I don't know which direction the entire mass of water will go. In fact I've seen samples from two different sags in the same line where one was basic and one was acidic.

I'd use spoolable composite pipe for the line and forget about the corrosion risks. The two high pressure spoolable composites that I've used with succes are FuturePipe (formerly Hydril,

http://www.futurepipe.com/usa/inner.asp?P_SectionID=28&P_CategoryID=112,

they have a 4.5" ID rated at 2250 psig) and FlexPipe systems

http://www.flexpipesystems.com/prodata.html

but they don't have an ANSI 600 product yet.

David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com

Please see FAQ731-376 for tips on how to make the best use of Eng-Tips Fora.

The harder I work, the luckier I seem

 

[dcasto]

CO2 becomes hydroscopic at pressures above its critical point. There are several good papers on Acid Gas Injection. Typically, there is enough water removed in the compression stages such that the discharge from the compressor is undersaturated. One system I worked on discharged at 500 psig and the model predicted freewater. As the gas went down the injection well bore the pressure increased. The model predicted that by the time the gas was 500 feet down hole, there would be no freewater. After about 2 years of operation the injection string had a leak. When the tubing was pulled, the first 300 feet of tubing was severlt corroded, just as the model predicted.

Saying all that, the added security of 304SS vs CS on 1000 meters of line is worth the extra cost.

 

[jeap]

It is a good sugestion using a plastic line, however I think Futurepipe provision is not possible in the region (Patagonia)in time and cost. I think that ERFV (Epoxi reinforced plastic) used to injection water at high pressures could be an alternative. This material is commonly provided for local suppliers. Reviewing technical info it is possible to handle wet CO2 up to 66 C.

Thinking ahead, some other lines could be changed in material, vg. drains and vents...I'm checking conditions.

Well, I really, really thank you all for help and in the future I'll let you know the results...

jeap

 

[zdas04]

I wouldn't rule them out without talking to them first. On their home page they have regions they serve and one division serves the U.S. and Latin America and it looks like the coverage goes all the way to the southern tip of South America. I've found their material price to be lower than steel over the last couple of years and I've heard of places where you can lay 1 mile/hour (ploughed in to depths close to your 1m).

David

 

[shoffman83]

We have a similar gas misture and do dehydrate to 7 lbs/MMSCFD. C/S on pipleines and well heads. Everything works pretty good. Some good stuff in GPSA on this, you should read. Freewater would be bad for the piping, so the first post of checking cooled saturated temperatures is worthwhile. You should dehydrate below saturation conditions of the pipeline.

 

[jeap]

shoffman83,

Are you using a TEG unit in order to dehydrate the gas mixture?

If so, where is it located: interstage or after compression?

Have you observed/meassured corrosion in the compressor interestages?

Considering CO2 a supercritical fluid at P y T after compression I 'assume' that remaining water is to be 'dissolved' in the bulk before entering the wellhead, thus free water should not be present.

On the other hand, models as those explained in GPSA are not in good agreement each other as you can see when compare the figures for CO2, even in the same databook. More...calculations of final moisture using Peng-Robinsong package in hysys differs in great manner from those obtained using sour Peng-Robinson...


I know this is very difficult to estimate, but actually TEG is not to be installed at the beginning of the operation. However, some routine wall thickness meassurements are to be done as well as installation of corrosion coupons to monitoring corrosion rates.