This study aims to investigate the technological and economic prospects of integrated gasification facilities for power (IGCC) and Fischer-Tropsch (FT) liquid production with and without CCS over time. For this purpose, a component based experience curve was constructed and applied to identify the potential performance improvement of integrated gasification facilities. The results of the experience curve were compared with a bottom-up technology analysis conducted in previous work (Meerman et al., 2012). Results indicate that substantial cost reductions and performance improvements are possible, especially for IGCC with CCS. For instance, the costs of electricity production (COE) may decrease from 82€2008/MWh at present to 50€2008/MWh in 2050, if solid oxide fuel cells become commercially available (with a constant coal price of 2.25€2008/GJ). This cost decrease can only be realized if installed IGCC capacity increase to over 600GWe and installed CCS capacity to over 3000GWe equivalent. Also IGCC without CCS have considerable learning potential, with COE projected to decrease from the current 60 to 40€2008/MWh in the long term. Furthermore, the COE of IGCC without CCS could be competitive with the current market price in the short term. Initial support is, however, needed to realize the first 20GWe. Currently, coal-based FT-liquids are already competitive at an oil price of 77€2008/bbl for FT-liquids without CCS and of 83€2008/bbl with CCS, resulting in CO2 capture costs of only 11€2008/tCO2. By 2050, production costs of FT-liquids could drop to 9.3€2008/GJ for FT-liquids without CCS and to 10€2008/GJ for FT-liquids with CCS. To realize this cost reduction, an installed capacity of about 430GWth_FT is needed. The bottom-up and the component based experience curve analyses gave comparable trends regarding the potential development of efficiency, capital costs and production costs for a scenario with a strong growth in IGCC, FT and CCS capacity. The main advantage of combining the two approaches is that it becomes clear how cost reductions can be achieved, what kind of capacity development and the time frame is required to reach the projected improvements.@en

The aim of this study is to assess whether the value of flexibility can influence the investment decision between CO₂ ship and pipeline transport and, therefore, the way the infrastructure develops. For this, the value of a carbon capture and storage project are calculated with the standard net present value (NPV) and with the least-squares Monte Carlo method, which is a real option approach (ROA).Results of the NPV and ROA show that ships are preferred for small volumes over large distances. For instance, for a design capacity of 2.5Mt/y, pipelines are preferred for 250km and ships for 500km. The ROA shows that the option value to abandon the project and to switch off the CO₂ capture unit temporarily are about 2-4 and 5 times as high for the ship compared to the pipeline configurations, respectively. The option to connect to another storage reservoir has a value of >1000M€ for the 10MtCO₂/y configurations. Consequently, this option turns the project values positive for the 10MtCO₂/y pipeline and shipping configurations over a distance of 250 and 500km.Overall, the value of flexibility did not change the preferred transportation mode from pipeline to ship transport, at least for the considered options to abandon the project, switch off the capture unit temporarily and switch to another storage reservoir. However, under the assumptions made, all 10MtCO₂/y cases were not profitable with the NPV approach, while they were profitable with the ROA.

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In this study, a new cost model is developed for CO₂ pipeline transport, which starts with the physical properties of CO₂ transport and includes different kinds of steel grades and up-to-date material and construction costs. This pipeline cost model is used for a new developed tool to determine the configuration leading to the lowest levelized costs for CO₂ transport, for point-to-point pipelines as well as for simple networks on different types of terrain and for different time frames. The model optimizes inlet pressure, diameter, steel grade and number of pumping stations. Results show that gaseous CO₂ transport can give lower levelized costs than liquid CO₂ transport for point-to-point pipelines and for simple networks, if the CO₂ is stored in a reservoir with a low required injection pressure, like depleted natural gas fields. However, for storage fields with a required injection pressure of 8MPa or higher (like aquifers), CO₂ can be better transported in a liquid form. For onshore pipelines transporting liquid CO₂, the optimal inlet pressure is 9-13MPa and pumping stations are installed roughly every 50-100km. For offshore pipelines, pumping stations are not an option and the inlet pressure is determined by the length of the pipeline. The maximum inlet pressure is about 25MPa and for even longer pipelines, a larger diameter is selected. The levelized costs (excluding initial compression) for transporting 100kg/s (about 3Mt/y) over 100km are between 1.8 and 3.3€/t for liquid and 4.0-6.4€/t for gaseous CO₂ transport. For larger mass flows the costs are decreasing, for instance transporting 200kg/s (about 6Mt/y) over 100km are 1.2-1.8€/t for liquid and 3.0-3.8€/t for gaseous CO₂ transport.Furthermore, results show that higher steel grades lead to lower investment costs for onshore pipelines transporting liquid CO₂. Using X120 in the long term reduces the pipeline costs up to 17%. For gaseous CO₂ transport, lower steel grades (like X42 and X52) are the best option. Also offshore pipelines do not benefit from the development of higher steel grades over time because the thickness should be at least 2.5% of the outer diameter. The results indicate that oversizing the pipeline, to transport CO₂ from an additional source that is coming available later, is not always cost-attractive. This strongly depends on the time span of which further CO₂ sources are available and on the mass flows. Oversizing appears earlier cost-attractive compared to two point-to-point pipelines if the source with the largest mass flow becomes available first.

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This study analyses the impact of technological improvements and increased operating experience on the techno-economic performance of integrated gasification facilities producing electricity and/or transportation fuels. Also, the impact of using torrefied biomass instead of coal and/or applying CCS is examined. Results indicate that current production costs of electricity and/or transportation fuels are above market prices. Future improvements, however, could reduce production costs sufficiently to make gasification facilities economical. Furthermore, although CCS can be used to reduce CO2 emissions at relative low CO2 avoidance costs, only the use of biomass allows the production of carbon neutral electricity and/or transportation fuels and in combination with CCS can even result in negative CO2 emissions.@en

The aim of this study was to analyze whether, and if so, in what way risks would influence the design, costs and routing of CO₂ pipelines. This article assesses locational and societal risks of CO₂ pipeline transport and analyses whether rerouting or implementing additional risk mitigation measures is the most cost-effective option. The models EFFECTS and RISKCURVES are used to estimate the dispersion and risk, respectively. The pipeline routes are optimized by using the least cost path function in ArcGIS. This article evaluates three case studies in the Netherlands. The results show that pipelines transporting dense phase CO₂ (8-17MPa) with a minimal amount of risk mitigation measures already meet the 10^-6 locational risk required in the Netherlands. 10^-6 locational risks of 135m are calculated for intermediate pumping stations, handling 450kg CO₂/s (about 14Mt CO₂/year). In all the cases, pumping stations could be located along the pipeline route without any problem.For the cases studied transporting gaseous CO₂ (1.5-3MPa) leads to larger 10^-6 locational risk distances than transporting dense phase CO₂. This is caused by the large momentum behind a dense phase CO₂ release, leading to smaller but higher jet and to a higher mixing rate with the surrounding air than for a gaseous CO₂ release. Based on our analysis, it can be concluded that dense phase CO₂ transport is safe if it is well organized. The risks are manageable and widely accepted under current legislation. In addition, risk mitigation measures, like marker tape and increased surveillance, are available which reduce the risk significantly and increase the costs only slightly. Pipeline routing for gaseous CO₂ transport appears more challenging in densely populated areas, because larger safety zones are attached to it.

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This study analyses the impacts of technological improvements and increased operating experience on the techno-economic performance of integrated gasification (IG) facilities. The facilities investigated produce electricity (IGCC) or FT-liquids with electricity as by-product (IG-FT). Results suggest that a state-of-the-art (SOTA) coal-fired IGCC without CO2 capture has electricity production costs of 17€/GJ (60€/MWh) with the potential to decrease to 11€/GJ (40€/MWh) in the long term. Specific direct CO2 emissions may drop from about 0.71kgCO2/kWh to 0.59kgCO2/kWh. If CO2 is captured, production costs may increase to 23€/GJ (83€/MWh), with the potential to drop to 14€/GJ (51€/MWh) in the long term. As a result, CO2 avoidance costs would decrease from 35€/t CO2 to 18€/t CO2. The efficiency penalty due to CCS may decrease from 8.8%pt to 3.7%pt.CO2 emissions can also be reduced by using torrefied biomass (TOPS) instead of coal. Production costs of a SOTA TOPS-fired IGCC without CO2 capture are 18-25€/GJ (64-92€/MWh). In the long term, this may drop to 12€/GJ (44€/MWh), resulting in CO2 avoidance costs of 7€/t CO2. The greatest reduction in anthropogenic CO2 emissions is obtained by using biomass combined with carbon capture and storage (CCS). A SOTA TOPS-fired IGCC with CCS has, depending on the biomass price, production costs of 25-35€/GJ (91-126€/MWh) with CO2 avoidance costs of 19-40€/t CO2. These values may decrease to 15€/GJ (55€/MWh) and 12€/t CO2 avoided in the long term. As carbon from biomass is captured, specific direct CO2 emissions are negative and estimated at -0.93kgCO2/kWh for SOTA and -0.59kgCO2/kWh in the long term. Even though more carbon is sequested in the future concepts, specific emissions drop due to an increase in the energetic conversion efficiency of the future facilities. New technologies in IG-FT facilities have a slightly smaller impact on production costs. In the long term, production costs of FT-liquids from coal may drop from 13€/GJ to 9€/GJ if CO2 is vented and from 15€/GJ to 10€/GJ if CCS is applied. The use of TOPS results in 15-23€/GJ (Vent) and 17-24€/GJ (CCS) for SOTA facilities. These production costs may drop to 11-18€/GJ (Vent) and 12-19€/GJ (CCS) in the long term. Contrary to the IGCC cases, the coal-fired IG-FT facility shows the lowest CO2 avoidance costs. The CO2 emission of coal to FT-liquids with CCS is, however, similar to gasoline/diesel production from crude oil.@en

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, 0.8-5.5M€2010/km for a pipeline diameter of 0.8m and a length of 25km. For the five mass flow based cost models evaluated in this study, a cost range is found of, for instance, 0.9-2.1M€2010/km for a mass flow of 750kg/s over 25km (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 0.91m 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 0.8m. 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, 3.1-3.6M€2010 for a booster station with a capacity of 1.25MWe. Therefore, validation of the booster station cost is required before such models are applied in further research.@en

Ill this article, an economic optimization tool is developed takmg into account different steel grades, inlet pressure, diameter and booster stations for point-to-point pipelines as well as for simple networks. Preliminary results show that gaseous C02 transport is cost effective for relatively small mass flows and short (trunk) pipelines. For instance, for a pipeline transporting 5 Mt/y over 100 km of agricultural ten-am. gaseous transport would cost 10.2 €/t and liquid transport 12.1 €/t (including initial compression). In terms of materials, the results indicate that higher steel grades (X70) are the most cost effective for onshore pipelines transporting liquid CO2 while for gaseous CO2 lower steel grades (X42) are more cost effective.@en

This study aimed to analyze whether, and how, uncertainty influences the layout and costs of a CO2 transportation network. The case without uncertainty is modelled with a perfect foresight (PF) model and with uncertainty with the real option approach (ROA). In this study, uncertainties in the CO2 price, tariff received per tonne of CO2 transported, the willingness, probability and moment that sources join the CO2 transportation network are incorporated in the analysis. The results show that uncertainty leads to higher required CO2 prices before investments in carbon dioxide capture and storage (CCS) are made. With a volatility of 47% in the CO2 price, the required CO2 price almost triples in comparison with the net present value approach. Hence, under uncertainty less sources are retrofitted with CCS and less CO2 is captured and stored over time. For instance, for the analyzed case study 31 Mt and 137 Mt CO2 is projected to be captured in the base scenario of ROA and PF model, respectively, in the period 2015-2050. If the volatility of the CO2 price is reduced with 50%, 96 Mt is projected to be captured in the ROA, which is still about one third less than in the PF model.Furthermore, the results show that uncertainty leads to less development of trunklines. All this leads to an increase in the transport and storage costs. For instance, for our case study, the average CO2 transport and storage costs in 2050 increase from 2.8 €/t to 13 €/t in the base scenario of the ROA compared to the PF model. If the volatility is reduced with 50%, the transport and storage costs decrease to 7.5 €/t in the ROA, which is still 2.5 times as much as in the PF model.Our findings indicate that the implementation of CCS can best be stimulated by reducing the volatility of the CO2 price, reducing capture costs and facilitating cooperation between nearby sources.@en