Service Life GRP Pipe for Supercritical Saturated CO2  

Thread by Kate Stuart on 02 Mar 2009 at 22:25:51 
We are orienting ourselves on pipeline solutions for CO2 (99.84% pure carbon dioxide) transport from, among others, coal plants to empty natural gas reservoirs. The fact that the water content in the CO2 is close to saturation (under the ball park assumption that the saturation water fraction in supercritical 17N carbon dioxide is 4E-3 from Spycher and Pruess, 2005) combined with the chemical reaction of - among other species - Carbon dioxide with Water under formation of Carbonic Acid leads to a requirement for long term corrosion resistant pipeline solutions. Two conceptual solutions have our current interest:

- Retrofitting on existing pipeline infrastructure by corrosion and pressure resistant coating / liner solutions (FBE corrosion resistant coating).

- For new pipelines: fibre reinforced plastics. Glass fibre reinforced Epoxy or Vinyl Ester based.

In line with my own thoughts and after skimming your site it might be that the acidic environment, and possible forthcoming resin, glass fibre and/or matrix degradation is a key parameter in the lifetime of the frp or coating solution chosen. Hence, I am interest in CO2, H2O and ion permeation and subsequent or simultaneous chemical degradation and resulting mechanical retention. My questions are a follows:

- Is ultimate chemical attack of the glass fibre plastic laminate the major service life factor? Or is the solubility of carbon dioxide in polymers at the current pressure and resulting resin swelling of more concern?

- Can your software predict chemical surface reactions by acid in combination with diffusion and simultaneous glass fibre corrosion?

- Does for diffusion of Carbonic Acid the electroneutrality relationship including the Maxwell-Stefan balance hold?

- What is the isotherm of supercritical in epoxy or vinyl ester based materials? I am little bit afraid of extreme high solubilities at 100 bar system pressure (supercritical gases have the tendency to dissolve as a liquid). The low free volume of properly cured resin systems probably makes things worse. What is worrying also is that one can find very limited information on glass reinforced epoxy or fusion bonded epoxy for CO2 transport piping solution. Is there for example any experience with GRE for CO2 transport in Europe, Canada or America?

- Is what are the pro's and con's of metal (steel) pipeline solutions compared to GRE? Our interest is long term pipe operation, at least a lifetime of 100 years.

- If we would make the pipe from Glass Reinforced Epoxy (GRE), what material should we use for related components, such as valves, orifice plates, pressure tanks and so on.

- I am interested in the permeation and corrosion simulator (CheFEM) and the possibilities of Abaqus (hoop stress, buckling stress, optimized grp laminate definition, sudden pressure drop scenarios, maximum pipeline pressure of coatings solutions) with this regard.

Thanks, and looking forward to hearing from you.

Kate Stuart

    Comment by Horst Stocker on 05 Apr 2009 at 21:35:08  | |responses: 4|
    Can anyone suggest an appropriate model or calculation method for supercritical carbon dioxide and water, solubility and diffusivity as a function of the species temperature and pressure. If we would assume Sanchez-Lacombe (SL) equation of state, how would this influence the swelling behaviour of GRP and subsequent CO2 and H2O time lag, permeation rates and decrease in mechanical properties (assuming one sided exposure in atmospheric outside conditions). I am experiencing a fundamental lack regarding the previous, so please help!


      Comment by Krish on 13 May 2009 at 22:22:11  | |responses: 3|
      Sanchez-Lacombe is an extended form of Flory Huggins solutions theory. Just to otbain a ball park I would recommend to use the Flory-Huggins solution theory, also for CO2 in GFRP: the concept of enthalpy, entropy, binary interaction parameter based on solubility parameters and the behaviour as a function of temperature (using enthalpy of mixing and enthalpy of vaporization) are all laid down rather well (some time ago already, but that should not be reason to neglect!). All the principles are there, and fitting parameters are not required (and that is my problem with all the other thermodynamical theories: from my viewpoint the amount of fitting parameters is a good measure for the insignificance of a certain thermodynamical theory - but ok I am an engineer).


        Comment by Composite Analytica on 16 May 2009 at 13:37:36  | |responses: 2|

        Unfortunately Flory-Huggins theory does not include pressure effects in a proper manner, hence a model - when using a lattice thermodynamic model - like Sanchez-Lacombe is the way to go. There are also other models (PC-SAFT) etc.

        Composite Analytica

          Comment by Kate on 17 May 2009 at 14:20:36  | |responses: 1|
          Can we obtain Sanchez-Lacombe EOS charasteric parameter data (mass density in close-packed state at 0K, hypothetical cohesive energy data in close-packed state and the temperature related to the potential energy well depth) for different grades of Epoxy Resin?


            Comment by Krish on 17 Jul 2009 at 20:19:03  | |responses: 0|
            Thanks to all.

            I've been some time offline, let us proceed with the subject: Carbon Dioxide diffusion, solubility, permeation, service life, ageing, fatigue and composite materials: Sanchez Lacombe ! CO2, DNV: the composite, coating, steel material challenge of the current moment !


    Comment by Rodney on 02 Mar 2009 at 22:27:59  | |responses: 5|
    From the viewpoint of the CO2 pipeline material decision, supercritical CO2 transport is indeed the challenge of the current moment. Among others, the phenomenon of condensation of acid on the pipeline wall (indeed the solubility of water at the 100 bar is very low, hence in no circumstance carbonic acid formation will be prevented) will require at least an epoxy / vinyl ester based - or similar material - as structural material or coating. This is mainly due to the required lifetimes (at least more than a hundred years) of a carbon dioxide piping system.

    With regard to current developments: DNV is developing a standard with industrial partners (link: DNV CO2 standard development). Others who have an interest or opinion regarding this thread: please share your thoughts and ideas on this subject.


      Comment by Tim on 01 Sep 2009 at 16:40:21  | |responses: 4 |

      If you look at the solubility of water in CO2, solubility is increasing after a certain point. An example from Sintef energy: pure CO2, 25C, from 65 bar the solubility of water in CO2 increasing when pressure increases, 1100 ppm-3300 ppm water in CO2 stream. If you dry your CO2 stream between each compression step and afterwards to for example 50 ppm, I would not expect free water in my pipeline (not by condensation), or do I miss something.

      I think some pipeline system will not be there for 100 years, this totally depends on the needed lifetime of the assets (CO2 source, transport line and injection years at the well). Asset managers are not spending more money then neccesary i think....

      Let me know!


        Comment by Rodney Bennet on 01 Sep 2009 at 20:58:52  | |responses: 3|

        Thanks Tim for rejuvenating this actual topic!

        Concerning the Water content in high pressure CO2: my impression is that an increasing CO2 pressure reduces the saturation fraction for Water. With a minimum around the critical point. Subsequently there is indeed an increase, but this is minor. At 30 degrees Celsius and pressures of 100 bar and larger, the saturation fraction stabilizes in the order of 4000 ppm. This saturation fraction is roughly ten times less than atmospheric air at 30 degrees Celsius, and hence equals a relative humidity of 10% in these conditions. Any amount above this fraction, will condensate on the wall and react with CO2 under formation of Carbon Acid.

        Drying might be possible - at least theoretically - but are you aware of large volume industrial equipment that does this job economically? The 10% relative humidity example at 30 degrees Celsius does not make me very confident with this regard.

        Now, my chemical-physical gut feel is that the appropriate fibre reinforced epoxy system could be suitable. Probably there are also some interesting multilayer solutions (polymer - metal with an annular interface).

        Here an interesting related case story I found on this site: In the near future, natural gas pipelines (type X-52, X-60, X-65 and X-70) may also be used for transport of Hydrogen or even Carbon Dioxide. In case of Hydrogen conveyance, Hydrogen might be mixed with Natural Gas (parallel gas transport, using a membrane to seperate the gases at the outlet) or transported solely. Discarded natural gas pipelines may also be completely retrofitted for Hydrogen or Carbon Dioxide transport. With regard to Hydrogen, a service life concern could be HISC (Hydrogen Initiated Stress Cracking) of steel. Hydrogen embrittlement or HISC results from combining of diffusing Hydrogen atoms into molecular Hydrogen - or the formation of molecular Methane - in internal metal voids of nanoscopic size. The generated pressure - in combination with intrinsic circumferential stress in the material - can exceed the restrain pressure of steel, especially near the loading surface. Whether HISC is an issue is largely dependent on the sort of steel, internal pressure and temperature. Click here for the case: Using Epoxy Coating for Pipeline Retrofitting

        Regards, Rodney

          Comment by Tim on 02 Sep 2009 at 19:38:39  | |responses: 2|
          Hey Rodney,

          Always interested in CO2 :D.

          I think from an economical point of view drying towards very low ppm levels is doing the trick (state of the art technology is already much applied with relatively low costs) and then just carbon steel (cheaper meter/ mile price) pipeline for long distance dense phase CO2 transport.

          The only thing where I am interested in, is what the exact effect of SOx, NOx, H2S, Ar, O2, H2,etc as a contaminent (like max 5% in the stream) in my CO2 stream is on corrosion (chemical and physical) of my carbon steel pipeline. The stream assumed to be dry to like 50 ppm as an example. What will be the tresholds of these contaminents and why?

          Keep the discussion ongoing!!! Maybe Composite Analytica can calculate that, with what model? How reliable is that model (what is the certainty in %)? How many mm/yr will be eaten by each of the contaminent? I think those are all lovely questions.............


            Comment by Rodney Bennet on 02 Sep 2009 at 20:58:46  | |responses: 1|

            Thanks for your message. Personally - also taking my example into account - I should not bother about the 50 ppm range - at least if you are able to remove the water also.

            Secondly, since I am not very familiar with chemical processing equipment, could you give an example of this state of the art drying technology which could dry below 4000 ppm in the conditions stated? Is it large sized drying bed equipment or what so ever? Thanks again.


              Comment by Tim on 09 Sep 2009 at 13:07:07  | |responses: 0|
              Hey Rodney,

              I know that glycerol solvents are mostly used to dry this stream. How big it is and what the costs are I do not directly know. But I think if you google "glycerol, drying, CO2" you will find some things. It of course also depends on the capacity required to dry. A lot of current CO2 pipelines in operation have such drying equipment. I suppose they have looked if it is economical....

              Good luck!