Abstract

Carbon Capture and Storage (CCS) is one of the most potential technologies to mitigate climate change. Usingpipelinesto transport CO2 from emission sources to storage sitesis one of common and mature technologies. The design and operation of pipeline transport process requires careful considerations of thermo-physical properties.This paper studied the impact of properties, including density, viscosity, thermal conductivity and heat capacity, onthe performance of CO2 pipeline transport. The pressure loss and temperature dropin steady state were calculated by using homogenous friction model and Sukhof temperature drop theory, respectively. The results of sensitivity study show thatover-estimating density and viscosity increases the pressure loss while under-estimating of density and viscosity decreases it. Over-estimating density and heat capacity leads to lower temperature drop while under-estimating of density and heat capacity result in higher temperature drop.This study suggests that the accuracy of property models for example, more accurate density model, should be developed for the CO2 transport design.

Abstract

International audience; The work presented in this paper forms part of the EC FP7 CO2PipeHaz project which aims to address the fundamentally important and urgent issue regarding the accurate prediction of fluid phase, discharge rate, emergency isolation and subsequent atmospheric dispersion during accidental releases from pressurised CO2 pipelines. Such pipelines are considered to be the most likely method for the transportation of captured CO2 from power plants and other industries to subsequent sequestration sites, and their safe operation is of paramount importance as their inventory is likely to be large. The developments presented describe a state-of-the-art, multi-phase heterogeneous discharge and dispersion model capable of predicting the near-field fluid dynamic and phase behaviour in such CO2 releases. Predicting the correct fluid phase during the discharge process in the near-field is of particular importance given the very different hazard profiles of CO2 in the gas and solid states. Validation of the model is undertaken using recently obtained experimental data from discharge tests. Model predictions are found to describe the experimental observations very well, with a high level of agreement between the two. The study clearly demonstrates that models addressing accidental releases of CO2 must include shock-capturing methods and complete three-phase formulations for prediction of the physical and thermodynamic properties of CO2 in order to accurately predict the discharge and dispersion phenomena of interest in risk assessments.

Abstract

International audience; Without a clear understanding of the hazards associated with the failure of CO2 pipelines, carbon capture and storage (CCS) cannot be considered as a viable proposition for tackling the effects of global warming. Given that CO2 is an asphyxiant at high concentrations, the development of reliable validated pipeline outflow and dispersion models are central to addressing this challenge. This information is pivotal to quantifying all the hazard consequences associated with the failure of CO2 transportation pipelines, which forms the basis for emergency response planning and determining minimum safe distances to populated areas. This paper presents an overview of the main findings of the recently completed CO(2)PipeHaz project [1] which focussed on the hazard assessment of CO2 pipelines to be employed as an integral part of CCS. Funded by the European Commission FP7 Energy programme, the project's main objective was to address this fundamentally important issue. Document type: Conference object

Abstract

This work studies the development of a sustainable hydrogen infrastructure that supports the transition towards a low-carbon transport system in the United Kingdom (UK). The future hydrogen demand is forecasted over time using a logistic diffusion model, which reaches 50% of the market share by 2070. The problem is solved using an extension of SHIPMod, an optimisation-based framework that consists of a multi-period spatially-explicit mixed-integer linear programming (MILP) formulation. The optimisation model combines the infrastructure elements required throughout the different phases of the transition, namely economies of scale, road and pipeline transportation modes and carbon capture and storage (CCS) technologies, in order to minimise the present value of the total infrastructure cost using a discounted cash-flow analysis. The results show that the combination of all these elements in the mathematical formulation renders optimal solutions with the gradual infrastructure investments over time required for the transition towards a sustainable hydrogen economy. Document type: Article

Abstract

Temporal variations in CO"sub"2"/sub" stream composition and mass flow rates may occur in a CO"sub"2"/sub" transport network, as well as further downstream when CO"sub"2"/sub" streams of different compositions and temporally variable mass flow rates are fed in. To assess the potential impacts of such variations on CO"sub"2"/sub" transport, injection, and storage, their characteristics must be known. We investigated variation characteristics in a scenario of a regional CO"sub"2"/sub" emitter cluster of seven fossil-fired power plants and four industrial plants that feed captured CO"sub"2"/sub" streams into a pipeline network. Variations of CO"sub"2"/sub" stream composition and mass flow rates in the pipelines were simulated using a network analysis tool. In addition, the potential effects of changes in the energy mix on resulting mass flow rates and CO"sub"2"/sub" stream compositions were investigated for two energy mix scenarios that consider higher shares of renewable energy sources or a replacement of lignite by hard coal and natural gas. While resulting maximum mass flow rates in the trunk line were similar in all considered scenarios, minimum flow rates and pipeline capacity utilisation differed substantially between them. Variations in CO"sub"2"/sub" stream composition followed the power plants’ operational load patterns resulting e.g., in stronger composition variations in case of higher renewable energy production. Temporal variations in CO"sub"2"/sub" stream composition and mass flow rates may occur in a CO"sub"2"/sub" transport network, as well as further downstream when CO"sub"2"/sub" streams of different compositions and temporally variable mass flow rates are fed in. To assess the potential impacts of such variations on CO"sub"2"/sub" transport, injection, and storage, their characteristics must be known. We investigated variation characteristics in a scenario of a regional CO"sub"2"/sub" emitter cluster of seven fossil-fired power plants and four industrial plants that feed captured CO"sub"2"/sub" streams into a pipeline network. Variations of CO"sub"2"/sub" stream composition and mass flow rates in the pipelines were simulated using a network analysis tool. In addition, the potential effects of changes in the energy mix on resulting mass flow rates and CO"sub"2"/sub" stream compositions were investigated for two energy mix scenarios that consider higher shares of renewable energy sources or a replacement of lignite by hard coal and natural gas. While resulting maximum mass flow rates in the trunk line were similar in all considered scenarios, minimum flow rates and pipeline capacity utilisation differed substantially between them. Variations in CO"sub"2"/sub" stream composition followed the power plants’ operational load patterns resulting e.g., in stronger composition variations in case of higher renewable energy production. Document type: Article

Abstract

This study aims to provide a systematic overview and comparison of capital and O&M costs models for CO2 pipelines and booster stations currently available in literature. Our findings indicate significantly large cost ranges for the results provided by the different cost models. Two main types of capital cost models for pipeline transport were found in literature, models relating diameter to costs and models relating mass flow to costs. For the nine diameter based models examined, a capital cost range is found of, for instance, 0.8–5.5 M€2010/km for a pipeline diameter of 0.8 m and a length of 25 km. For the five mass flow based cost models evaluated in this study, a cost range is found of, for instance, 0.9–2.1 M€2010/km for a mass flow of 750 kg/s over 25 km (TRUNK-25). An important additional factor is that all capital costs models for CO2 pipeline transport, directly or indirectly, depend on the diameter. Therefore, a systematic overview is made of the various equations and parameter used to calculate the diameter. By applying these equations and parameters to a common mass flow, height difference and length result in diameters between 0.59 and 0.91 m for TRUNK-25. The main reason for this range was different assumptions about specific pressure drop and velocity. Combining the range for diameter, mass flow and diameter based cost models gives a capital and levelized cost range which varied by a factor 10 for a given mass flow and length. The levelized cost range will further increase if the discrepancy in O&M costs is added, for which estimations vary between 4.5 and 75 €/m/year for a pipeline diameter of 0.8 m. On top of this, most cost models underestimate the capital costs of CO2 pipelines. Only two cost models (namely the models who relate the costs to the weight of the pipeline) take into account the higher material requirements which are typically required for CO2 pipelines. The other sources use existing onshore natural gas pipelines as the basis for their cost estimations, and thereby underestimating the material costs for CO2 pipelines. Additionally, most cost models are based on relatively old pipelines constructed in the United States in the 1990s and early 2000s and do not consider the large increase in material prices in the last several years. Furthermore, key model characteristics are identified for a general cost comparison of CCS with other technologies and a system analysis over time. For a general cost comparison of CCS with other technologies, pipeline cost models with parameters which have physical or economic meaning are the preferred option. These are easy to interpret and can be adjusted to new conditions. A linear cost model is an example of such an model. For a system analysis over time, it is advised to adapt a pipeline cost model related to the weight of the pipeline, which is the only cost model that specifically models thickness of the pipeline and include material prices, to incorporate the effect of impurities and pipeline technology development. For modeling booster station costs, a relation between capacity and costs including some economies of scale seems to be the most appropriate. However, the cost range found in literature is very large, for instance, 3.1–3.6 M€2010 for a booster station with a capacity of 1.25 MWe. Therefore, validation of the booster station cost is required before such models are applied in further research.

Abstract

The main goal of this study is to identify knowledge gaps and uncertainties in Quantitative Risk Assessments (QRA) for CO2 pipelines and to assess to what extent those gaps and uncertainties affect the final outcome of the QRA. The impact of methodological choices and uncertain values for input parameters on the results of QRA’s have been assessed through an extensive literature review and by using commercially available release, dispersion and effect models. It is made apparent that over the full life cycle of a QRA knowledge gaps and uncertainties are present that may have large scale impact on the accuracy of assessing risks of CO2 pipelines. These encompass the invalidated release and dispersion models, the currently used failure rates, choosing the type of release to be modeled and the dose-effect relationships assumed. Also recommendations are presented for the improvement of QRA’s for CO2 pipelines.

Abstract

In the framework of the CCSP R&D program, the regulatory gaps have been assessed at VTT using the current monitoring rules for capture, pipeline transportation and geological storage of CO"sub"2"/sub" as a benchmark. The scope of the presented work includes: (i) definition of CO"sub"2"/sub" emissions from ship transportation of CO"sub"2"/sub"; (ii) review of EU regulations on MRV of maritime CO"sub"2"/sub" emissions; and (iii) review of the MRV regulation on capture, transport and geological storage of CO"sub"2"/sub" under the EU-ETS. The considered activities related to ship transportation of CO"sub"2"/sub" are liquefaction and intermediate storage with recirculation loop for boil-off CO"sub"2"/sub", loading and unloading facilities and CO"sub"2"/sub" transportation and handling during the ship voyage. Identification of the regulatory gaps, based on the above, shows what is needed to enable ship transportation of CO"sub"2"/sub" for geological storage in Europe. Based on the results, maritime transportation for CCS could be made possible with very limited new emission monitoring and verification practices. Also the trade-offs of using an MRV regulation analogous to pipeline transportation of CO"sub"2"/sub" is discussed in the results.

Abstract

This paper provides a method to identify drivers, barriers and synergies (DBS) related to the deployment of a CO2 pipeline network. The method was demonstrated for the West Mediterranean region (WMR) (i.e. Spain, Portugal and Morocco). The method comprises a literature review, analysis of embedded pipeline trajectories, interviews with experts, and workshops with stakeholders. Subsequently, the collected information was used to identify route specific DBS in several CO2 pipeline network deployment scenarios that were modeled for the WMR. Most identified DBS apply to CO2 pipeline transport in general. The barriers (e.g. technical knowledge gaps, outstanding legislative issues, lack of financial incentive) can in principle be tackled to make the design, construction and operation of a CO2 pipeline network possible, but could sometimes lead to somewhat higher costs. Furthermore, there are also facilitating processes (e.g. experience with CO2 pipeline transport for EOR). Cost benefits due to pipeline oversizing were identified as a route specific driver, whereas crossings of mountains, water and nature areas are route specific barriers. Installing CO2 pipelines along natural gas pipelines could be either a route specific synergy or barrier, depending on site conditions. Finally, several key measures were proposed to enable CO2 pipeline networks in the future.

Abstract

This paper addresses technical and operational aspects pertaining to the transport of CO2. It deals with lessons learnt from the development of three large CCS demonstration projects: the UK-based Don Valley project, the Dutch ROAD project, and the Spanish Compostilla project. These projects were all selected by the European Commission in 2009 to receive funding under the European Energy Programme for Recovery (EEPR). The purpose of the demonstration projects is to verify feasible capture techniques (i.e. gasification, flue-gas cleaning, and oxy-coal combustion in circulating fluidised bed, respectively), and to demonstrate geological storage options, off-shore and on-shore. As the distance and elevation of the CO2 transport system are inherently given by the project, the transport conditions for the CO2 will generally differ from one project to another.The demonstration projects have shown that the thermophysical nature of CO2 is prone to complicate certain operational procedures mainly due to phenomena like phase change, hydrate formation and Joule-Thomson cooling. The front-end engineering design studies suggest, however, that the handling of CO2 is quite feasible during normal operation, although customised solutions may be required to handle transients like emergency shut-down and pipeline re-pressurisation. This implies that CO2 transport is not seen as an insuperable hurdle to the design and operation of large CCS systems.