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Graphical abstract Highlights • Energy balance (data and model) of a CO 2 injection facility is presented. • Heat flow and efficiency of ambient air vaporizers are analyzed. • Operation conditions are compared for single- and two phase CO 2 flux. • Warm and cold injection schemes are evaluated. Abstract Injection of 67 kt carbon dioxide was carried out between 2008 and 2013 at the test site for geological storage in Ketzin, Germany. The source carbon dioxide was delivered in liquid phase. The injection facility has had a three step process chain: (i) pressure increase by a liquid pump, (ii) temperature increase by ambient air vaporizers and (iii) temperature increase by an electrical vaporizer including phase change to gaseous conditions. The ambient vaporizers reduced electrical power demand but the weather dependence induced some kind of uncertainty, further their power could not be measured. In the cases when the carbon dioxide was evaporated within the ambient vaporizers, the heat demand increased such that the driving temperature was not enough for full vaporization. However, the gas to liquid ratio is unknown wherefore the heating power can not be calculated over the ambient vaporizer. This is addressed, as the electric energy consumption was most reduced during the two phase operation. For these intervals, two phase gas–liquid conditions prevailed in the pipeline. Unlike conjectured, flow conditions remained stable and did not vary significantly from single phase behavior. The current work – for the first time – presents a detailed analysis of energy input and losses of the carbon dioxide injection process based on field data and simulations. A modified process chain is proposed to switch the electric energy demand to an ambient heat source, reducing the electrical energy use per ton carbon dioxide by up to 90 %. The work provides insight for planning future injection devices that involve liquid carbon dioxide in the process chain. [ABSTRACT FROM AUTHOR]

Abstract: Given the development of power plants with integrated capture of carbon dioxide and the subsequent storage of this captured CO2 (CCS—carbon dioxide capture and storage) the future fossil fuel-based energy system will most likely consist of very different types of processes and units. Past studies mostly focused on a very specific part of this CCS system. The effects and reactions on bordering processes were often only rudimentally considered. Due to these complex interactions between individual parts of a CCS system it is necessary to examine the behaviour of the whole system in order to achieve secure and efficient operation. This article intends to highlight problems that will occur when such interactions are not considered and examined properly. This work presents an approach for the examination of a system consisting of a power plant, capture unit, transport system and CO2 storage facility. A number of typical problems are shown, with focus on the examination of thermodynamic behaviour of the captured CO2 in a pipeline followed by a well in a saline aquifer storage site. It is shown that, under special conditions, the combination of a CO2 pipeline and a well down to a saline aquifer will not work due to phase changes and pressure conditions, which would lead to operational problems or at the very least to partial destruction of either the pipes or the sedimentary storage rock. [ABSTRACT FROM AUTHOR]

Abstract: This paper investigates methods to predict potential injection rates of CO2 into a saline aquifer and analyses the sensitivities of the input parameters. Geological parameters are based on conditions at the European CO2 Onshore Research Storage and Verification Project in Ketzin, Germany, and varied within an acceptable range. Two injection regimes for CO2 are analysed: pressure controlled injection and power plant controlled injection, where the CO2 flux depends on the load curve of a 600MWnet lignite power plant. The results are determined with a numerical model and compared to an analytical solution with constant pressure injection. The injection rates depend mainly on the geological setting and only slightly on technical parameters. Aquifer permeability and thickness show approximately linear sensitivity and have a dominant impact. Depth is also of high importance, but the impact is more complex and is based on geothermal temperature and hydrostatic gradient, which affect viscosity, compressibility and caprock stability. Vertical anisotropy is insensitive. The difference in the mean rate between constant pressure injection and power plant controlled injection is 8%. Peak injection rates are 29% above mean injection rates, which shows that the reservoir can effectively dampen rate variations. The analytical solution predicts the highest injection rates, the lowest temporal variability and decreasing rates with injection duration. The numerical solution predicts a stronger temporal variability and the rates increase with duration. In the initial phase the differences between the methods add up to a factor of 1.45. [ABSTRACT FROM AUTHOR]