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Abstract
As Carbon Capture and Storage slowly gets accepted and integrated as a mean for cleaner utilization of fossil fuels, accurate knowledge of the transport of CO2 through pipelines and into wells becomes crucial. A representative North Sea transport and injection scenario into a depleted gas field is being analysed in this study through numerical simulations of the flow during steady state and dynamic operation. The balance between gravitational and frictional presssure drop is being described in details for this specific case, with a focus on the operability of the transport system. Dynamic simulations during an Emergency Shut Down are being analysed, exhibiting very low temperatures at the wellhead that could require the addition of a heater or of a low temperature tubing.

Introduction
As energy needs around the globe are rising, simultaneously with concerns about the environmental impact of human activities, Carbon Capture and Storage has been put forward as a way to mitigate the detrimental effects of fossil fuels as an energy source. Significant efforts were thus spent in the past decade to evaluate the technical and economical feasibility of mass CO2 storage, with most work focusing on (a) the capture of CO2 from flue gases via different processes and (b) the characterization of different kinds of reservoir to evaluate their reliability as a CO2 storing medium on geological time scales. Less attention was paid to the task of transporting CO2 from the capture to the storing sites. However, transport and injection of CO2 as part of a complete CCS chain presents its own limitations and restrictions in the design of the chain. Proper analysis of the challenges associated to transport is therefore key to the design of an operably and economically viable CCS venture. 

In the context of this paper, transport is defined from the outlet of the compressor or pump station up to and including the tubing of the injection wells. Detail aspects of the transport scenario being analysed here correspond to injection into a depleted gas field. Such a reservoir type was chosen for it is the most probable candidate for CCS in Northern Europe. The overall conclusions drawn in this study are however not so much dependent on the type of reservoir used and can easily be extrapolated to other reservoir types or even depth, as was shown by Paterson et al. [1].

Apart from the economical constraints of expensive, large ID and often submerged pipelines, there are technical restrictions on the injection rates and injection conditions. These requirements on the injection stem from limitations set by, for instance:

- Thermal or hydraulic cracking in the reservoir due to the large influx of cold CO2.
- Well integrity of the tubing, casing and cement linked to large pressure and temperature gradients along the well.
- The possibility of CO2 hydrates forming in the near well bore area, due to the presence of water from the reservoir.
- Water or even carbon ice formation at lowest temperatures.
- Noise, pulsations and vibration induced by high flow velocities.

In the current activities, the wellhead and downhole temperatures are often the strictest constraints, combined with the limitations on the mass flow rate due to pipe vibrations and erosion. Although the injection fluid is often clean and can be considered particle free, during operation scenarios such as for instance a shut-in, temporary back flow might occur. In that case the fluid cannot be considered to be particulate free and an erosion limit must be considered. Therefore, the transport of CO2 is severely constrained by the allowable injection conditions. In this paper, the basics of CO2 transport and injection are discussed with respects to these limiting conditions. The pressure and temperature profiles in the well are first discussed for different operating conditions, providing insights into the balance of forces at play during CO2 injection, followed by one dynamic operating scenario.