Acid Gas Injection Pipeline

[AggieCHEN04]

I appologize for the repost. I have recieved some good input for this thread in the Chemical Plant forum, but I think that this is propably a more appropriate forum for this subject.


I have a mixture of acid gas that is (by mass) 73% CO2, 26% H2S, and about 0.2% H2O with trace hydrocarbons. The acid gas is compressed to 1100 psig and then flows to the injection well through a buried carbon steel pipeline.

My concern is that of an aqueous phase may condense one the gas hits the colder pipeline and cause localized corrosion. Should I be worried? Are there any good epoxy coatings for this type of application? I had originally planned on dehydrating the gas, but I have run into some budgetary and time constraints.

To give you some more information about the process:

The gas is assumed to come out of the air cooler at 120F after the final stage of compression. Actual operating conditions will probably vary somewhat. According to my simulations the acid gas would actually be fully condensed at about 100F at the design pressure. At slightly lower pressure and aqueous phase would form between 120 and 100.


The composition can vary from 90% CO2 to the design conditions.

The pipeline will be in East Texas, probably buried a couple of feet deep.

The flow regime is fully turbulent; somewhere around 300,000 to 500,000 Reynolds number if liquid and 1.3 million if gas.

 

[grampi1]

Is the design one where you count on the acid gas being supercritical dense phase to assure sufficient head down the well? If yes, then all the water came out in the compressor after coolers prior to the dense phase transition. Unless water is added to the process stream after the dense phase transition, no more water will drop out and no corrosion will occur. Lots of experience in Alberta with this type of setup.

 

[AggieCHEN04]

Is the design one where you count on the acid gas being supercritical dense phase to assure sufficient head down the well? If yes, then all the water came out in the compressor after coolers prior to the dense phase transition. Unless water is added to the process stream after the dense phase transition, no more water will drop out and no corrosion will occur. Lots of experience in Alberta with this type of setup.

There is a small amount of water remaining in the acid gas after the final compression stage. It's difficult to say whether or not the concentration will be high enough to form a separate aqueous phase or if it will be soluble in the dense phase if the gas is sufficiently cooled in the pipeline.

In this case, the theoretical critical pressure is not achieved, but the temperature and pressure are borderline for acid gas and water condensation. This is all contingent on the accuracy of the simulator and actual operating conditions. I can't really accurately predict if the aqueous phase or the acid gas will condense first because their dewpoints are so close at these conditions.

You say you're from Alberta? I've been doing some internet research to see if I can find operational acid gas injections sites, and I came across a spreadsheet published by Tartan Engineering that details the acid gas compositions, type of dehydration, injection pressure and pipeline material of various injection sites in western Canada. One site that stuck out in my mind was a Thompson Lake.

One thing I thought was odd was that there were several sites that mixed produced water with the acid gas at the surface. Why is that done this way? I noticed sites that did this didn't have any dehydration or insulation and had carbon steel pipelines. Is this because the produced water already has corrosion and hydrate inhibitors in it?

 

[AggieCHEN04]

Bump...really hoping for a Grampi response. He's got me interested.

 

[bewdley]

Probably different, but it may possibly help. I had an H2S + CO2 + HC pipeline not always dry as it should have been. The pipe was 310 ss. In some 6 to 7 years operation, no visible corrosion occurred in test spots.
Some troubles (but this was clearly a project bug) in a few carbon steel parts due to embrittlement - later changed with killed carbon steel, but too late to evaluate behaviour (plant was decommissioned one year later).
For a sour service like the one you describe, always require NACE compliant metals.

 

[SJones]

Epoxy coatings will not help you. The dominant corrosion mechanism will be H2S corrosion owing to the CO2:H2S ratio. You may be lucky and get good, protective sulphide films; but, do you want your pipeline integrity to hang on sulphide film formation? As long as you do not dehydrate the gas, there is a threat of high corrosion rates; maybe not under normal operating conditions but it would only take a small upset now and again to give trouble. Have a look at this document:

http://www.capp.ca/default.asp?V_DOC_ID=763&PubID=83667

it may give you some pointers.

Steve Jones
Materials & Corrosion Engineer

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

 

[AggieCHEN04]

I have read of a few instances where corrosion inhibitors have been used for this application. Does anybody have any experience with this? How much do corrosion inhibitors cost?

 

[maddocks]

We have designed a number of acid gas injection schemes. Early designs utilized 304/304L. Recent designs are trending more towards select chem carbon steel, typically smls to avoid HIC problems. This is based on the undersaturated designs that are often used. Even minor excursions of free water will not cause excessive problems. However, if water is a regular occurence, move into a stainless product.

You can contact me if you require more information.

Jim Maddocks, P.Eng.
V.P. Engineering
jmaddocks@gasliquids.com
403-250-2950