Design of CO2 Transmission Pipeline Systems

Anthropogenic CO₂ coming from CCS plays by different rules than pure CO₂ normally found in pipelines. Important considerations include: pipeline hydraulics, running ductile fracture mitigation and pipeline rupture dispersion modeling applying the knowledge base available at the time of design. 

Hydraulics | how fluids move through pipelines

Anthropogenic CO₂ sources contain impurities that cause dramatically different behavior in flow through a pipe (hydraulics) than pure CO₂, whose thermodynamic properties are well known. The primary concern for the engineer here is determining an appropriate equation-of-state (EoS) relationship for the mixture, which directly affects pipeline design. Rather than using the Span and Wagner EoS generally used to model pure CO₂, the Peng Robinson EoS was selected for initial design as it proves more accurate when impurities exist in the stream.

Next, a study of the effects of various impurities on the transportation of dense phase CO₂ was performed in order to establish an engineering baseline to the tariff requirements for anthropogenic CO₂ supply.  The study builds upon published findings by P. Seevam, et al. which states that “phase properties of CO₂ vary with impurities, generally increasing the two-phase region and changing the critical temperature and pressure of the mixture.” [Ref. 1] 

A typical pipeline operates at 1100 to 2200 psig and between 60° to 90°F. The attached figures indicate the movement of the phase envelope into this typical operating region.  Of all the impurities, hydrogen shows the greatest influence on the phase envelope. For operators, this means an increase in impurities would require the minimum operating pressure be increased to a level above the phase envelope for all temperature regimes.  The impact would be a reduced operating envelope and potentially additional intermediate pumping stations to maintain more consistent pipeline pressure.

Figure 1: Influence of Impurities on Phase Envelope of CO₂ Fluid Mixtures

Additionally, multiple compositions were analyzed for their direct impact to transportation, i.e. pressure drop along the pipeline.  For a simulated 1 mile segment of 24” OD pipeline transporting 1.0 Bscfd the pressure drop for all but one of the compositions was about 15 psi/mile.  The 95% CO2; 3% N2; 2% H2 case resulted in a 32 psi/mile pressure drop.

Figure 2: Effect of Impurities on Pressure Loss in 1 mile of Pipe

To better quantify these results, a 100 mile segment of 24” OD pipeline transporting 600 mmscfd was analyzed with four (4) representative compositions.  The results show the pressure drop increase nearly linear as impurities were added to the fluid.

Figure 3: Effect of Impurities on Pressure Loss Over 100 miles of Pipe

Based on these findings, it was recommended that the maximum content of nitrogen be limited to 3% and hydrogen limited to 1%.  Other impurities did not have a significant impact to the performance of the fluid and therefore CO₂ concentrations less than 95% could be tolerated hydraulically provided the nitrogen and hydrogen limitations are maintained.

The final impurity investigated, hydrogen sulfide (H₂S) which, even in low concentrations, has a significant impact on the corrosion of the pipeline. Usually H₂S occurs in such low concentrations that it has a negligible impact to pipeline operations, but unfortunately it is often found in higher concentrations in anthropogenic sources.  Pipeline steels with yield strengths greater than 65,000 psi must be individually qualified to be compliant with NACE MR0175/ISO 15156 for use in sour service unless the partial pressure of H2S is maintained below 0.3 kPa (0.043 psi).  For a liquid CO₂ system, this translates to a maximum concentration of about 45 ppm.