Article

A method for assessing infrastructure for CO 2 utilization: A case study of Finland

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Abstract

Synthetic hydrocarbons can be produced sustainably with power-to-gas processes, resulting in a net reduction of greenhouse gas emissions due to the substitution of conventional natural gas and other fossil fuels with carbon-neutral alternatives. Acquisition of the for the synthetic fuel production can be implemented in multiple ways. This work introduces a node-based model to assess different implementation strategies of utilization systems, taking into account temporal effects, regional variation, and economies of scale for capture. Intermediate storage volumes, capture costs, transport quantities, and other relevant infrastructural aspects of the CCU system can be estimated with the model. Finland is used as a case study, focusing specifically on the national and regional scale. capture costs are significant, being nearly four times larger than the cost of storage in the baseline scenario (354 M€, 85 M€). sources with smaller annual emissions increases capture costs by 14% compared to baseline. This increase in cost is comparable to the cost of transporting over a quarter of all captured to off-site processing (varying distance, 100–400 km). Seasonal storage of is found to be beneficial for the cost-efficient production of synthetic fuels, owing to the temporal disparity between emissions and utilization, as well as the overall cost structure of the components. Five key decision categories are proposed for a carbon utilization system: scale, type, units, location, and technological decisions. These may be applied to describe any carbon utilization system, helping to form a more comprehensive picture of a future energy system, where carbon is widely used as a raw material.

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... Capture of biogenic carbon dioxide from the outgoing flows from pulping is still a little studied subject (Leeson et al., 2017), but recent studies have found the application of BECCS in pulp mills technically feasible (IEAGHG, 2016;Kuparinen et al., 2019). Previous studies in this area have mainly focused on modeling of carbon capture integration in kraft pulp mill operation (Kuparinen et al., 2019;Onarheim et al., 2017a), estimation of costs (Fuss et al., 2018;IEAGHG, 2016;Karjunen et al., 2017;Onarheim et al., 2017b) or the possible scale or emission reduction potential (Leeson et al., 2017;Fuss et al., 2018;Kuparinen et al., 2019, IEA, 2020. The most studied capture method is the commercial monoethanolamine (MEA) post-combustion process (Karjunen et al., 2017;Leeson et al., 2017;Onarheim et al., 2017a). ...
... Previous studies in this area have mainly focused on modeling of carbon capture integration in kraft pulp mill operation (Kuparinen et al., 2019;Onarheim et al., 2017a), estimation of costs (Fuss et al., 2018;IEAGHG, 2016;Karjunen et al., 2017;Onarheim et al., 2017b) or the possible scale or emission reduction potential (Leeson et al., 2017;Fuss et al., 2018;Kuparinen et al., 2019, IEA, 2020. The most studied capture method is the commercial monoethanolamine (MEA) post-combustion process (Karjunen et al., 2017;Leeson et al., 2017;Onarheim et al., 2017a). Based on earlier estimates, the cost of CO 2 avoided in pulp mills ranges between 20 and 92 € per ton of CO 2 depending on the chosen processes and mill details (Fuss et al., 2018;IEAGHG, 2016). ...
... Based on the literature, the cost of carbon capture from the flue gases of pulp and paper mill combustion processes or biomass combustion varies in the range of 40-92 €/ t CO2 (IEAGHG, 2016;Karjunen et al., 2017;Leeson et al., 2017;IEA, 2020;Kearns et al., 2021). In this study, an estimation of 62 €/t CO2 was used in all cases, including energy costs and assuming a MEA-based process and capture from one source of flue gas. ...
Article
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Bioenergy with carbon capture and storage (BECCS) is one of the key negative emission technologies (NETs). Large-scale implementation of BECCS has been criticized of the associated increase in land use. The existing large Nordic pulp and paper production units enable BECCS deployment without additional land use, as they currently release large amounts of bio-based carbon dioxide (CO2). The application of BECCS in pulp mills has been found technically feasible in earlier studies. This study explores key factors that affect the propensity to invest in BECCS in different types of existing European pulp and paper mills. The results give fresh understanding on the effects of BECCS on the market price of pulp and paper products and the required level of incentives. Based on statistical data, the marginal carbon dioxide credit (€ per ton CO2) to make BECCS profitable was derived. The results show that the required level of credit greatly depends on the mill type and details and that the feasibility of BECCS does not clearly correlate with the economic performance or the measured efficiency of the mill. The most promising mill type, a market kraft pulp mill, would find BECCS profitable with a credit in the range of 62-70 €/t CO2 and a credit of 80 €/t CO2 would decrease pulp production costs by 15 €/t product on average if 50% of CO2 emissions was captured. The EU Emission Trading System (ETS) is the main policy instrument to achieve the climate targets related to fossil energy use, but does not yet contemplate bio-based emissions.
... Several strategies for avoiding the emission of anthropogenic CO 2 into the atmosphere such as conversion from CO 2 to chemicals, fuels and biotechnological conversion are today considered with much attention as it could reduce the climate change impact [13]. Karjunen et al. [14] introduced a nodebased model to assess different implementation strategies of CO 2 utilization system, taking into account temporal effects, regional variation, and economies of scale for CO 2 capture in Finland. ...
... For each node in the model, we should ensure that all the nodes follow the mass balance law, which stipulating that all CO 2 captured at or flowing into a node must be equal to that injected or transported out of the node. Eq. (14) ensures that this balance holds. ...
... Several studies have been published on assessing the CO2 sources of a country and on the construction of a special grid for captured CO2. Karjunen et al. [31] presented a case study for Finland focusing on the basic elements of the grid. Reiter et al. [3] presented a case study for Austria that focused on using the CO2 generated in several parts of the country for a power-to-gas model through a CO2 grid. ...
... Therefore, CO2 transportation is a complex phenomenon and a lot of work has to be put into the subject to be able to design a CO2 grid capable of accepting the CO2 generated in one place and transport it to consumer facilities. In this work, it was assumed that the CO2 is transported from a great distance and the feed-in parameters are selected according to the calculations of Karjunen [31], as presented in Table 3. ...
Article
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... TABLE  Technical and Financial Assumptions Newly Added to the LUT Energy System Model to Update the Biogas and PtG Technology Production Processes. Hydrogen storage [15] CO2 storage [16] Capacity 155,951 [MWhH2] 3,300 [tonCO2] Capex 0.298 [€/kWhH2] 891 [€/tonCO2] Opex 3 [% of capex p.a.* ] 1 [% of capex p.a. ] Efficiency [%] 100 100 Life-time [a] 30 30 Energy/power ratio (h) 369Self-Discharge (%/h) 0* p.a. = per annum ...
Conference Paper
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In this paper, the "LUT Energy System model" based on linear algorithm with an hourly resolved configuration is used to assess the role of hydrogen in 100% renewable energy (RE) based power and industrial gas sectors. The study is done for 2030 assumptions. A mix of RE technologies and energy storage options is applied to provide energy security and system flexibility. The three chosen case study countries are Germany, Finland and Egypt. In countries with sustainable biomass resources, depending on the optimised cost, the model assumes that 60 mol.% of feedstock is converted into biomethane (CH4) and the remaining 40 mol.% is CO2 produced together as biogas. Therefore, the costs of H2 to SNG conversion drops due to no extra cost for capturing the required CO2 from air. The LUT model with additional biogas-to-SNG options and new functionality is called the Enhanced model and the regular model is called the Standard model. The results reveal that in the Enhanced model, where readily available CO2 is captured from biogas, hydrogen production plays a vital role in securing a 100% RE powered system. This results in a lower cost of the energy system, in particular for Egypt (9% lower at 35 €/MWh) and Germany (3% lower at 62 €/MWh) in the Integrated scenario, where the gas demand for industrial sector is high. However, for Finland the decrease is only 1% to 54 €/MWh. Moreover, lower full load hour of electrolysers, additional installed capacity of hydrogen and higher system flexibility emphasise the benefits of hydrogen in the total energy system.
... Karjunen et al. [80] also studied the development of power-to-gas value chains in Finland using biogenic carbon sources. They used a node-based material balance tool, which monitors the carbon flow across the energy systems and estimated all the CCU related costs. ...
Article
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Carbon capture and utilization (CCU) is recognized by the European Union, along with carbon, capture and storage (CCS), as one of the main tools towards global warming mitigation. It has, thus, been extensively studied by various researchers around the world. The majority of the papers published so far focus on the individual stages of a CCU value chain (carbon capture, separation, purification, transportation, and transformation/utilization). However, a holistic approach, taking into account the matching and the interaction between these stages, is also necessary in order to optimize and develop technically and economically feasible CCU value chains. The objective of this contribution is to present the most important studies that are related to the individual stages of CCU and to perform a critical review of the major existing methods, algorithms and tools that focus on the simulation or optimization of CCU value chains. The key research gaps will be identified and examined in order to lay the foundation for the development of a methodology towards the holistic assessment of CCU value chains.
... 5 papers [158][159][160][161][162] are published in the fields of utilizing CO 2 as novel fuels. ...
Article
Carbon Capture, Utilization and Storage, also referred to as Carbon Capture, Utilization and Sequestration (CCUS), is one of novel climate mitigation technologies, by which CO2 emissions are captured from sources such as fossil power generation and industrial processes, and further either reused or stored.
... In recent study, Karjunen et al. (2017) studied the application of CO 2 capture, transport, and intermediate storage logistics for Finnish energy system based on renewable energy sources. The cost of biogenic CO 2 for utilization varied between 40 and 44 €/t,CO 2 depending on applied future scenario. ...
Article
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Corporate image, European Emission Trading System and Environmental Regulations, encourage pulp industry to reduce carbon dioxide (CO2) emissions. Kraft pulp mills produce CO2 mainly in combustion processes. The largest sources are the recovery boiler, the biomass boiler, and the lime kiln. Due to utilizing mostly biomass-based fuels, the CO2 is largely biogenic. Capture and storage of CO2 (CCS) could offer pulp and paper industry the possibility to act as site for negative CO2 emissions. In addition, captured biogenic CO2 can be used as a raw material for bioproducts. Possibilities for CO2 utilization include tall oil manufacturing, lignin extraction, and production of precipitated calcium carbonate (PCC), depending on local conditions and mill-specific details. In this study, total biomass-based CO2 capture and storage potential (BECCS) and potential to implement capture and utilization of biomass-based CO2 (BECCU) in kraft pulp mills were estimated by analyzing the impacts of the processes on the operation of two modern reference mills, a Nordic softwood kraft pulp mill with integrated paper production and a Southern eucalyptus kraft pulp mill. CO2 capture is energy-intensive, and thus the effects on the energy balances of the mills were estimated. When papermaking is integrated in the mill operations, energy adequacy can be a limiting factor for carbon capture implementation. Global carbon capture potential was estimated based on pulp production data. Kraft pulp mills have notable CO2 capture potential, while the on-site utilization potential using currently available technologies is lower. The future of these processes depends on technology development, desire to reuse CO2, and prospective changes in legislation.
... Tabelle 2: Kapitalgebundene und betriebsgebundene Kosten der PtX-Anlagen ( Albrecht et al. 2016;Buttler und Spliethoff 2017;Brynolf et al. 2018;Eller 2015;Fasihi et al. 2016;Karjunen et al. 2017;Keith et al. 2018;König 2016;Mohseni et al. 2013;Noack et al. 2014;Zapf 2017, IEA 2019 Die Eingangswerte der wichtigsten Prozessparameter der PtX-Anlagen sind in Tabelle 5 dargestellt. ...
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Power-to-X (PtX) technologies are currently under discussion as a possible option for the production of sustainable liquid and/or gaseous hydrocarbons especially for GHG neutral mobility. However, the implementation of such technologies often fails due to the considerable electrical power requirements arising for the production of PtX products (summarizing here Power-to-Liquid (PtL) and Power-to-Gas (PtG) options). At the same time, there is an increasing share of renewable energies from volatile sources within the German electricity grid, which is increasingly causing electricity production peaks to be compensated by expensive measures. These throttled electricity quantities are referred to either as market-based or grid-based “surplus electricity”. In the discussion about PtX, it is repeatedly demanded to convert this surplus electricity via PtX processes into high-quality liquid and/or gaseous fuels instead of not using the available electrical energy—and additionally paying for that. Thus the goal of this paper is it to take a closer look at this aspect of the debate. The economics of the PtX process for the provision of liquid and/or gaseous fuels in competition to other PtX processes related to the use of this “surplus electricity” is assessed. Therefore, additionally Power-to-Heat (PtH) processes are considered. For this purpose, a comparison is made between the maximum electricity prices permitted for break-even production and the operating hour-based PtX product production costs of the main PtX products PtL diesel, PtL kerosene, PtG methane, hydrogen and heating via PtH.
... A MATLAB script from a previous work was utilized for performing the simulations [63]. Computations were performed in parallel, and over 2 million cases were simulated in total. ...
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... The electrochemical carbon dioxide (CO 2 ) reduction reaction (CO 2 RR) enables the conversion of CO 2 and intermittent renewable electricity into valuable chemicals and fuels [1][2][3][4][5]. Technoeconomic studies emphasize that commercially feasible CO 2 RR systems will need to operate at current densities greater than 150 mA/cm 2 to reduce electrolyzer capital costs [6,7]. ...
... coal-fired power plants) or directly from the atmosphere (e.g. direct air capture) can be used as feedstock for the production of a wide range of added-value chemicals, such as methanol, formic acid and ethylene [1]. This contrasts with conventional carbon capture and storage (CCS), which brings about no tangible economic benefits. ...
Article
Methanol from captured CO2 provides a more sustainable alternative to gasoline due to its low carbon footprint, yet it requires a large amount of renewable energy that could be used instead to decarbonise the electricity mix. A techno-economic and environmental analysis of methanol produced from captured CO2 and renewable energy is conducted to shed light on the transportation-power nexus. The investigated scenarios differ in how the carbon-free energy source – electricity from wind – is used to either decarbonise the electricity mix or produce green methanol to displace conventional fossil fuels. The assessment is carried out for six countries that differ in the composition of their electricity mix and gasoline consumption. The results of this holistic assessment show that, at present, decarbonising the electricity grid using renewable energy sources and carbon capture and storage would offer greater environmental benefits, without incurring large changes in direct economic costs, compared to producing methanol from the hydrogenation of captured CO2. Though this insight might change in the future if the carbon intensity of the mix is reduced and green methanol becomes cheaper, it highlights the need to consider the transportation-power nexus in assessing alternative fuels and thereby prevent shifting of emissions from one sector to another over their life cycle.
... A comparative analysis of the aerogel along with other building insulator materials highlighted that the level of energy saving as well as avoided CO 2 are higher in the case of aerogel. In other work, synthetic hydrocarbons can be produced in a sustainable manner via power-to-gas processes [33], thereby leading to an overall net reduction in greenhouse gas emissions that is a result of substituting conventional natural gas and other hydrocarbons with carbon neutral alternatives. This scenario-driven approach was developed according to a node-based model as part of a case study investigation in Finland. ...
Article
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... 8-10 CO 2 is utilized for the manufacturing of inorganic and organic compounds such as sodium bicarbonate 11 and salicylic acid. CO 2 is also used in the production of synthetic fuels 12,13 (like methane, methanol 14,15 and dimethyl ether (DME) 4,16 ). It can also be used directly in applications comprising welding medium, firefighting equipment, solvent, refrigerant, dry ice, and process fluid. ...
Article
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... Welder et al. [27] combined GIS tools with mixed integer linear programming to optimize hydrogen-based energy infrastructure containing cavern storages, wind turbines and hydrogen pipelines. Different implementation strategies for CO 2 -related transport infrastructure have also been studied [28]. ...
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Power-to-gas (PtG) is one option to integrate more renewable electricity production to the energy system, by offering flexible load, seasonal energy storage and low-GWP (Global Warming Potential) methane. The first step of the PtG process, hydrogen production by water electrolysis, requires electricity with low specific CO2 emissions. Therefore, the operation of electrolyser is most likely variating according to the intermittency of renewable electricity production. The downstream processes of PtG should be capable to follow the dynamics and utilize the produced hydrogen, avoiding curtailment. This could be done with a very dynamic reactor system, or with aid of buffer storages for feed gases. This paper studies the effect of dynamic properties of methanation reactor, hydrogen buffer storage and electrolyser full load hours on PtG system efficiency. The operation of electrolyser is following intermittent renewable electricity production and electricity markets, leading to varying full load hours (FLH) with different characteristics. Enhancement of single parameters related to thermal dynamics of the reactor could improve the system efficiency more than parameters related to the loading of the reactor. Coupled threshold were found for FLH and H2 storage size, after which average efficiencies became nearly similar as in steady-state operation.
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Sweden and Finland have national goals to reach net negative greenhouse gas emissions before mid-century. Achieving these ambitious goals could employ negative emission technologies, such as bioenergy with carbon capture and storage, but it is unclear how this technology could be realized in an energy transition. Sweden and Finland stand out for having a large share of substantial point source emissions of biogenic carbon dioxide, in the production of pulp, heat and power. In the European Pollutant Release and Transfer Register, Sweden and Finland reported 64% and 51% biogenic emissions, respectively, in facilities emitting over 100 kt of carbon dioxide in 2017, while the corresponding collective figure for all European states in the database is 6%. This qualitative study highlights company actors’ perspectives on bioenergy with carbon capture and storage within a Nordic regional context and explores their perspective on emerging tensions in the energy transition. Semi-structured interviews were conducted with 20 of the 24 companies with the largest point sources of biogenic emissions. The results are framed around four emerging tensions regarding bioenergy with carbon capture and storage from companies’ perspectives in this study: (1) absence of reliable long-term policies; (2) limits to companies’ climate change responsibility; (3) technical trade-offs of carbon capture; and (4) lack of customer demands for negative emissions. According to most of the companies, it is technically feasible to capture carbon dioxide, but it could be a challenge to determine who is responsible to create a financially viable business case, to enact supporting policies, and to build transport and storage infrastructure. Company representatives argue that they already contribute to a sustainable society, therefore bioenergy with carbon capture and storage is not their priority without government collaboration. However, they are willing to contribute more and could have an increasing role towards an energy transition in an international context.
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Economic uncertainty analysis of employing a membrane reactor (MR) equipped with H2O separation membranes for a synthetic natural gas (SNG) production as simultaneous power-to-gas and CO2 utilization technologies was carried out. Based on previously reported reaction kinetics, process simulation models were created for a conventional packed-bed reactor (PBR) and an MR. Deterministic economic analysis showed the unit SNG production cost of 1.67 $ kgSNG⁻¹ in an MR compared to 1.82 $ kgSNG⁻¹ in a PBR for a SNG production capacity of 1000 kg d⁻¹, showing about 8% cost reductions in the MR. From sensitivity analysis, raw material and labor were identified as the key economic factors to affect a unit SNG production cost for all cases studied. Stochastic economic analysis using a Monte-Carlo simulation method provided better insights for economic-uncertainty associated with premature technology like a SNG production in an MR using H2O separation membranes by presenting a wide range of SNG production costs and their probability.
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The Power-to-Gas (PtG) process chain could play a significant role in the future energy system. Renewable electric energy can be transformed into storable methane via electrolysis and subsequent methanation. This article compares the available electrolysis and methanation technologies with respect to the stringent requirements of the PtG chain such as low CAPEX, high efficiency, and high flexibility. Three water electrolysis technologies are considered: alkaline electrolysis, PEM electrolysis, and solid oxide electrolysis. Alkaline electrolysis is currently the cheapest technology; however, in the future PEM electrolysis could be better suited for the PtG process chain. Solid oxide electrolysis could also be an option in future, especially if heat sources are available. Several different reactor concepts can be used for the methanation reaction. For catalytic methanation, typically fixed-bed reactors are used; however, novel reactor concepts such as three-phase methanation and micro reactors are currently under development. Another approach is the biochemical conversion. The bioprocess takes place in aqueous solutions and close to ambient temperatures. Finally, the whole process chain is discussed. Critical aspects of the PtG process are the availability of CO2 sources, the dynamic behaviour of the individual process steps, and especially the economics as well as the efficiency.
Article
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Purpose Power-to-gas technology enables storage of surplus electricity from fluctuating renewable sources such as wind power or photovoltaics, by generating hydrogen (H2) via water electrolysis, with optional methane (CH4) synthesis from carbon dioxide (CO2) and H2; the advantage of the latter is that CH4 can be fed into existing gas infrastructure. This paper presents a life cycle assessment (LCA) of this technological concept, evaluating the main parameters influencing global warming potential (GWP) and primary energy demand. Methods The conducted LCA of power-to-gas systems includes the production of H2 or CH4 from cradle to gate. Product utilization was not evaluated but considered qualitatively during interpretation. Material and energy balances were modeled using the LCA software GaBi 5 (PE International). The assessed impacts of H2 and CH4 from power-to-gas were compared to those of reference processes, such as steam reforming of natural gas and crude oil as well as natural gas extraction. Sensitivity analysis was used to evaluate the influence of the type of electricity source, the efficiency of the electrolyzer, and the type of CO2 source used for methanation. Results and discussion The ecological performance of both H2 and CH4 produced via power-to-gas strongly depends on the electricity generation source. The assessed impacts of H2 production are only improved if GWP of the utilized electricity does not exceed 190 g CO2 per kWh. Due to reduced efficiency, the assessed impacts of CH4 are higher than that of H2. Thus, the environmental break-even point for CH4 production is 113 g CO2 per kWh if utilized CO2 is treated as a waste product, and 73 g CO2 per kWh if the CO2 separation effort is included. Electricity mix of EU-27 countries is therefore not at all suitable as an input. Utilization of renewable H2 and CH4 in the industry or the transport sector offers substantial reduction potential in GWP and primary energy demand. Conclusions H2 and CH4 production through power-to-gas with electricity from renewable sources, such as wind power or photovoltaics, offers substantial potential to reduce GWP and primary energy demand. However, the input of electricity predominately generated from fossil resources leads to a higher environmental impact of H2 and CH4 compared to fossil reference processes and is not recommended. As previously bound CO2 is re-emitted when CH4 is utilized for instance in vehicles, the type of CO2 source and the allocation method have a significant influence on overall ecological performance.
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This paper assesses possible scenarios for Northern Europe for transportation of CO2 in 2050 as part of a CCS infrastructure, giving focus on off-shore transportation. In addition, the possibility and costs for utilizing the solid Scandinavian bedrock for intermediate storage of CO2 is preliminarily assessed. The preliminary results indicate that an underground storage unit of 50 000 m3 or larger would have a significantly smaller investment cost than a similarly-sized steel tank storage complex. The cost for transporting CO2 from Finland to final geological CO2 storage sites abroad is higher compared to that from the coastal regions in countries around the North Sea. However, by joint transport infrastructure projects the industry and power production around the presented regions can reach significant cost reductions for CO2 transport. The ship transport infrastructure benefits from a model where nearby capture plants are connected by pipelines to exporting terminal hubs. Trunklines towards geological storage sites are especially cost efficient in the CO2 emission intensive regions close to the North Sea. The on-shore storage potential in western Latvia would also provide a promising opportunity for CO2 trunklines from other Baltics and from Finland. In the heavily CO2 emitting regions of northern Germany, the local on-shore storage accessed by trunklines from the surrounding areas would provide very competitive CO2 transport infrastructure for the local industry and power production. The results indicate that shared CO2 transportation infrastructure by ships would often be the best transport option from the Baltic Sea region to final storage sites at the North Sea. Especially the heavily industrialized regions on the shore of the Gulf of Finland can benefit from a shared transport infrastructure
Article
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In the carbon capture and storage (CCS) process, CO2 sources and geologic reservoirs may be widely spatially dispersed and need to be connected through a dedicated CO2 pipeline network. We introduce a scalable infrastructure model for CCS (simCCS) that generates a fully integrated, cost-minimizing CCS system. SimCCS determines where and how much CO2 to capture and store, and where to build and connect pipelines of different sizes, in order to minimize the combined annualized costs of sequestering a given amount of CO2. SimCCS is able to aggregate CO2 flows between sources and reservoirs into trunk pipelines that take advantage of economies of scale. Pipeline construction costs take into account factors including topography and social impacts. SimCCS can be used to calculate the scale of CCS deployment (local, regional, national). SimCCS’ deployment of a realistic, capacitated pipeline network is a major advancement for planning CCS infrastructure. We demonstrate simCCS using a set of 37 CO2 sources and 14 reservoirs for California. The results highlight the importance of systematic planning for CCS infrastructure by examining the sensitivity of CCS infrastructure, as optimized by simCCS, to varying CO2 targets. We finish by identifying critical future research areas for CCS infrastructure.
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The objective of this study is to give an overview of the potential for applying CCS in the Nordic countries (Sweden, Finland, Denmark, Norway and Iceland). The realistic potential of CCS in the region has been evaluated by taking into account existing and future energy systems and policies, emission sources, potential storage sites, technological, economical and political constraints as well as public acceptance. Special attention has been given to identifying promising regional CCS solutions that would have a significant CO2 emission reduction potential and could possibly involve cooperation between Nordic countries with synergical benefits for these. The report includes mapping of CO2 emissions in the Nordic countries from major sources, mapping and quantification of storage possibilities as well as scenarios of possible future CCS deployment in the region. In addition to the mapping, an overview of relevant CCS technology development and R&D activities in the Nordic countries is given. Public awareness of CCS, energy and climate policy frameworks, as well as political issues relevant to the deployment of CCS in the Nordic countries are also addressed.
Article
We present a stochastic decision-making algorithm for the design and operation of a carbon capture and storage (CCS) network; the algorithm incorporates the decision-maker’s tolerance of risk caused by uncertainties. Given a set of available resources to capture, store, and transport CO2, the algorithm provides an optimal plan of the CCS infrastructure and a CCS assessment method, while minimizing annual cost, environmental impact, and risk under uncertainties. The model uses the concept of downside risk to explicitly incorporate the trade-off between risk and either economic or environmental objectives at the decision-making level. A two-phase-two-stage stochastic multi-objective optimization problem (2P2SSMOOP) solving approach is implemented to consider uncertainty, and the ε-constraint method is used to evaluate the interaction between total annual cost with financial risk and an Eco-indicator 99 score with environmental risk. The environmental impact is measured by Life Cycle Assessment (LCA) considering all contributions made by operation and installation of a CCS infrastructure. A case study of power-plant CO2 emission in Korea is presented to illustrate the application of the proposed modeling and solution method.
Article
Carbon capture and storage (CCS) is an important technology option for reducing CO2 emissions into the atmosphere. The most commercially viable way to deploy CCS on a large scale is via coupling with enhanced oil recovery (EOR) operations. These operations allow the reduction of CO2 emissions through geological sequestration, coupled with generation of additional revenues through increased oil production as a result from CO2 re-injection through EOR. EOR also enables both CO2 utilization and storage (CCUS) as a carbon management strategy with long CO2 storage life. In practice, planning EOR operations takes into account mass balance and temporal aspects of a given site. When multiple oil reservoirs are involved, it is necessary to allocate the available CO2 supply and schedule suitable timing for EOR operations for these reservoirs. CO2 allocation and scheduling are thus important aspects in maximizing the economic benefits that arise from EOR operations. In this work, a mixed integer linear programming (MILP) model is developed to address CO2 allocation and scheduling issues for EOR operations. A discrete-time optimization approach is developed to consider both economic discounting and reservoir depletion. Two illustrative case studies are solved to illustrate the model.
Article
This paper investigates CO2 transport options and associated costs for CO2-sources in the Nordic region. Cost for ship and pipeline transport is calculated both from specific sites and as a function of volume and distance. We also investigate the pipeline volumetric break-even point which yields the CO2 volume required from a specific site for pipeline to become a less costly transport option than ship transport. Finally, we analyze possible effects from injectivity on the choice of reservoir and transport mode. The emission volumes from the Nordic emission sources (mostly industries) are modest, typically between 0.1–1.0 Mt per year, while distances to feasible storage sites are relatively long, 300 km or, in many cases, considerably more. Combined, this implies both that build-up of an inland CO2 collection system by pipeline will render high cost and that it is likely to take time to establish transportation volumes large enough to make pipeline transport cost efficient (since this will require multiple sources connected to the same system). At the same time, many of the large emission sources, both fossil based and biogenic, are located along the coast line. It is shown that CO2 transport by ship is the least costly transportation option not only for most of the sources individually but also for most of the potential cluster combinations during ramp-up of the CCS transport and storage infrastructure. It is also shown that cost of ship transport only increases modestly with increasing transport distance. Analyzing the effect of injectivity it was found that poor injectivity in reservoirs in the Baltic Sea may render it less costly to transport the CO2 captured from Finnish and Swedish sources located along the Baltic Sea by ship a further 800–1300 km to the west for storage in better suited aquifers in the Skagerrak region or in the North Sea.
Article
Capture and utilization of CO2 as alternative carbon feedstock for fuels, chemicals and materials aims at reducing greenhouse gas emissions and fossil resource use. For capture of CO2, a large variety of CO2 sources exists. Since they emit much more CO2 than the expected demand for CO2 utilization, the environmentally most favorable CO2 sources should be selected. For this purpose, we introduce the environmental-merit-order (EMO) curve to rank CO2 sources according to their environmental impacts over the available CO2 supply. To determine the environmental impacts of CO2 capture, compression and transport, we conducted a comprehensive literature study for the energy demands of CO2 supply, and constructed a database for CO2 sources in Europe. Mapping these CO2 sources reveals that CO2 transport distances are usually small. Thus, neglecting transport in a first step, we find that environmental impacts are minimized by capturing CO2 first from chemical plants and natural gas processing, then from paper mills, power plants, and iron and steel plants. In a second step, we computed regional EMO curves considering transport and country-specific impacts for energy supply. Building upon regional EMO curves, we identify favorable locations for CO2 utilization with lowest environmental impacts of CO2 supply, so-called CO2 oases.
Article
Large power sector CO2 emission reductions are needed to meet long-term climate change targets. Intermittent renewable energy sources (intermittent-RES) such as wind and solar PV can be a key component of the resulting low-carbon power systems. Their intermittency will require more flexibility from the rest of the power system to maintain system stability. In this study, the efficacy of five complementary options to integrate intermittent-RES at the lowest cost is evaluated with the PLEXOS hourly power system simulation tool for Western Europe in the year 2050. Three scenarios to reduce CO2 emissions by 96% and maintain system reliability are investigated: 40%, 60% and 80% of annual power generation by RES. This corresponds to 22%, 41% and 59% of annual power generation by intermittent-RES. This study shows that higher penetration of RES will increase the total system costs: they increase by 12% between the 40% and 80% RES scenarios. Key drivers are the relatively high investment costs and integration costs of intermittent-RES. It is found that total system costs can be reduced by: (1) Demand response (DR) (2-3% reduction compared to no DR deployment); (2) natural gas-fired power plants with and without Carbon Capture and Storage (CCS) (12% reduction from mainly replacing RES power generation between the 80% and 40% RES scenarios); (3) increased interconnection capacity (0-1% reduction compared to the current capacity); (4) curtailment (2% reduction in 80% RES scenario compared to no curtailment); (5) electricity storage increases total system costs in all scenarios (0.1-3% increase compared to only current storage capacity). The charging costs and investment costs make storage relatively expensive, even projecting cost reductions of 40% for Compressed Air Energy Storage (CAES) and 70% for batteries compared to 2012. All scenarios are simulated as energy only markets, and experience a "revenue gap" for both complementary options and other power generators: only curtailment and DR are profitable due to their low cost. The revenue gap becomes progressively more pronounced in the 60% and 80% RES scenarios, as the low marginal costs of RES reduce electricity prices.
Article
In 2005, the IPCC SRCCS recognized the large potential for developing and scaling up a wide range of emerging CO2 capture technologies that promised to deliver lower energy penalties and cost. These included new energy conversion technologies such as chemical looping and novel capture systems based on the use of solid sorbents or membrane-based separation systems. In the last 10 years, a substantial body of scientific and technical literature on these topics has been produced from a large number of R&D projects worldwide, trying to demonstrate these concepts at increasing pilot scales, test and model the performance of key components at bench scale, investigate and develop improved functional materials, optimize the full process schemes with a view to a wide range of industrial applications, and to carry out more rigorous cost studies etc. This paper presents a general and critical review of the state of the art of these emerging CO2 capture technologies paying special attention to specific process routes that have undergone a substantial increase in technical readiness level toward the large scales required by any CO2 capture system.
Article
CO2 capture, utilization, and storage (CCUS) technology has yet to be widely deployed at a commercial scale despite multiple high-profile demonstration projects. We suggest that developing a large-scale, visible, and financially viable CCUS network could potentially overcome many barriers to deployment and jumpstart commercial-scale CCUS. To date, substantial effort has focused on technology development to reduce the costs of CO2 capture from coal-fired power plants. Here, we propose that near-term investment could focus on implementing CO2 capture on facilities that produce high-value chemicals/products. These facilities can absorb the expected impact of the marginal increase in the cost of production on the price of their product, due to the addition of CO2 capture, more than coal-fired power plants. A financially viable demonstration of a large-scale CCUS network requires offsetting the costs of CO2 capture by using the CO2 as an input to the production of market-viable products. We demonstrate this alternative development path with the example of an integrated CCUS system where CO2 is captured from ethylene producers and used for enhanced oil recovery in the US Gulf Coast region. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd
Article
The intermittent nature of wind and solar power requires long-term energy storage options such as power-to-gas. This technology utilizes (surplus) electricity from renewable power sources to produce hydrogen in an electrolyzer. The produced hydrogen can be either directly utilized as an energy carrier or combined with CO2 and further converted to methane. This article evaluates different CO2 sources concerning their potential utilization within the power-to-gas energy storage technology with regard to capture costs, specific energy requirement and CO2 penalties. The results of a case study for Austria indicate that there is enough CO2 available from point sources to store all of the electricity produced from fluctuating renewable power sources (wind power plants and photovoltaics) via power-to-gas. Due to low capture costs, low CO2 penalties, biogenic origins, and short distances to wind power plants, biogas upgrading facilities and a bioethanol plant were determined to be the CO2 sources best suited for utilization in novel power-to-gas plants. However, as the total amount of CO2 produced from these facilities is relatively low in Austria, other CO2 sources would also be required. With moderate capture costs and CO2 penalties, power plants and an existing refinery could also provide CO2 for power-to-gas. Although large amounts of CO2 are available from iron, steel, and cement production facilities, these sources are not recommended for CO2 utilization in power-to-gas, as the CO2 penalty is relatively high and the facilities are rarely located near wind power plants in Austria.
Article
I. Statement of the problem, 232. — II. The evidence from some previous studies, 233. — III. The “.6 factor” rule and its application, 234. — IV. Specific evidence in a selection of metal processing and chemical industries, 236. — V. Studies of selected mineral industries, 239. — VI. Conclusions, 242.
Article
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).
Article
If CO2 capture and storage (CCS) is to become a viable option for low-carbon power generation, its deployment will require the construction of dedicated CO2 transport infrastructure. This paper describes the InfraCCS model, which can determine the likely extent and cost of the optimal least-cost CO2 transport network at European scale for the period 2015-2050, with 2015 the earliest foreseeable starting date of the CCS projects co-funded by the European Energy Programme for Recovery (EEPR), and 2050 the EU's target date for 80-95% reduction of greenhouse gas emissions. The computation is made possible by a number of methodological innovations compared to previous research, in particular: the use of k-means clustering to reduce the number of nodes in the network; the application of the Delaunay triangulation algorithm for pipeline pre-selection; and the introduction of a mathematically convenient yet realistic new pipeline costing model. The InfraCCS tool is applied to determine the optimal network corresponding to a CCS scenario that ensures near-complete decarbonisation of the European power sector. It is shown that the size of the CO2 network could range from 11,000 to 17,000 km by 2050, requiring 16-36 billion euros investment, with the higher numbers corresponding to the case when onshore aquifers are excluded as potential CO2 storage sites. Since the model shows that by 2030 more than half of the EU Member States could be involved in cross-border CO2 transport, international coordination seems crucial for the development of an optimised trans-European CO2 transport network.
Article
In this paper a novel integrated plant, designed for the co-production of electricity and synthetic natural gas (SNG), has been proposed as suitable strategy for renewable energy storage and CO2 emission control. The hydrogen generation by electrolysis and its use for SNG production is the approach chosen for the energy storage (chemical storage), while the CO2 control is performed by using (or recycling) the CO2, concentrated in the anode exhausts of a molten carbonate fuel cell, in the chemical processes of the plant (coal hydrogasification and SNG production processes). The proposed HyCRESt plant, acronym of Hydrogasification of Coal for Renewable Energy Storage, consists of three main sections: i) the hydrogasification island, in which the coal is gasified in hydrogen environment to a methane rich fuel gas stream (syngas); ii) the power island, in which the syngas is used as fuel for the electric power generation by using a molten carbonate fuel cell (MCFC) power unit; iii) the SNG island, in which the syngas is converted into a synthetic natural gas stream. The plant performance, in terms of co-production efficiency, CO2 avoided and fuel saving, has been evaluated by means of thermochemical and electrochemical models able to predict energy and mass balances. Results have pointed out that the co-production of electric and chemical powers allows to achieve system efficiencies greater than 55% with fuel saving values higher than 6% and CO2 avoided ranging from 20% (only electric power generation) to 120% (only SNG generation).
Article
Efforts to mitigate the impacts of climate change will require deep reductions in anthropogenic CO2 emissions on the scale of gigatonnes/yr. CO2 capture and utilization and/or storage technologies are a class of approaches that can substantially reduce CO2 emissions. Even though examples of this approach, such as CO2 enhanced oil recovery, are already being practiced on a scale >0.05 gigatonnes/yr, little attention has been focused on the supply of CO2 for these projects. Here, facility-scale data newly collected by the U.S. Environmental Protection Agency was processed to produce the first comprehensive map of CO2 sources from industrial sectors currently supplying CO2 in the United States. Collectively these sources produce 0.16 gigatonnes/yr but the data reveal the presence of large areas without access to CO2 at an industrially relevant scale (> 25 kilotonnes/yr). Even though some facilities with the capability to capture CO2 are not doing so and in some regions pipeline networks are being built to link CO2 sources and sinks, much of the country exists in "CO2 deserts". A life cycle analysis of the sources reveals that the predominant source of CO2, dedicated wells, has the largest carbon footprint further confounding prospects for rational carbon management strategies.
Article
We design a CO2 Capture, Utilization, and Sequestration (CCUS) supply chain network with minimum cost to reduce stationary CO2 emissions and their adverse environmental impacts in the United States. While doing so, we consider simultaneous selection of source plants, capture technologies, capture materials, CO2 pipelines, locations of utilization and sequestration sites, and amounts of CO2 storage. The CCUS costs include the costs of flue gas dehydration, CO2 capture, compression, transportation and injection, and revenues from CO2 utilization through enhanced oil recovery (CO2-EOR). The dehydration, capture, and compression costs are derived using advanced modeling, simulation, and optimization of leading CO2 capture processes. Our results suggest that it is possible to reduce 50–80% of the current CO2 emissions from the stationary sources at a total annual cost ranging $58.1–106.6 billion. Furthermore, it is possible to generate $3.4–3.6 billion of revenue annually through supplying CO2 for CO2-EOR. Overall, the optimal CCUS supply chain network would correspond to a net cost of $35.63–43.44 per ton of CO2 captured and managed. Such a cost-effective network for CO2 management is attained due to (i) using novel materials and process configurations for CO2 capture, (ii) simultaneous selection of materials and capture technologies, (iii) CO2 capture from diverse emission sources, (iv) CO2 utilization for enhanced oil recovery, and (v) nationwide CO2 storage. Results for the regional and statewide (Texas) CCUS are also favorable.
Article
A multiperiod stochastic programming model is developed for planning a carbon capture and storage (CCS) infrastructure including CO2 utilization and disposal in an uncertain environment and with a time-varying investment environment. An inexact two-stage stochastic programming approach is used to analyze the effect of possible uncertainties in product prices, operating costs, and CO2 emissions. The proposed model determines where and how much CO2 to capture, store, transport, utilize, or sequester for the purpose of maximizing the total profit of handling the uncertainty while meeting the CO2 mitigation target during each time period of a given planning interval. The capability of the proposed model to provide correct decisions despite a changing uncertain environment is tested by applying it to designing and operating the future CCS infrastructure on the eastern coast of Korea over a 20-year planning interval (2011–2030).
Article
In this study, a comprehensive infrastructure assessment model for carbon capture and storage (CiamCCS) is developed for (i) planning a carbon capture and storage (CCS) infrastructure that includes CO2 capture, utilization, sequestration and transportation technologies, and for (ii) integrating the major CCS assessment methods, i.e., techno-economic assessment (TEA), environmental assessment (EA), and technical risk assessment (TRA). The model also applies an inexact two-stage stochastic programming approach to consider the effect of every possible uncertainty in input data, including economic profit (i.e., CO2 emission inventories, product prices, operating costs), environmental impact (i.e., environment emission inventories) and technical loss (i.e., technical accident inventories). The proposed model determines where and how much CO2 to capture, transport, sequester, and utilize to achieve an acceptable compromise between profit and the combination of environmental impact and technical loss. To implement this concept, fuzzy multiple objective programming was used to attain a compromise solution among all objectives of the CiamCCS. The capability of CiamCSS is tested by applying it to design and operate a future CCS infrastructure for treating CO2 emitted by burning carbon-based fossil fuels in power plants throughout Korea in 2020. The result helps decision makers to establish an optimal strategy that balances economy, environment, and safety efficiency against stability in an uncertain future CCS infrastructure.
Article
Carbon capture and storage (CCS) is widely considered to be an essential technology for reducing carbon dioxide (CO2) emissions from sources such as power plants. It involves isolating CO2 from exhaust gases and then storing it in an appropriate natural reservoir that acts as a sink. Therefore, CCS is able to prevent CO2 from entering the atmosphere. In this work, a continuous-time mixed integer nonlinear programming (MINLP) model for CO2 source–sink matching in CCS systems is developed; the initial model is then converted into an equivalent mixed integer linear program (MILP). It is assumed that in CCS systems, CO2 sources have fixed flow rates and operating lives, while CO2 sinks have an earliest time of availability and a maximum CO2 storage capacity. Thus, the resulting optimization model focuses on important physical and temporal aspects of planning CCS. The usefulness of the model is illustrated using two case studies.
Article
This paper presents a comprehensive unified model for planning the retrofit of power plants with carbon capture (CC) technologies and the subsequent carbon dioxide (CO2) source-sink matching. The planning horizon is divided into time intervals that are not necessarily of equal duration, but which represent time slices generated by specific events (e.g. start and end of plant operation) occurring in the system as well as the required degree of flexibility in planning. In carbon capture and storage (CCS) systems, CO2 sources have variable flow rates and fixed operating lives, while CO2 sinks have finite injection rate and storage capacity limits, as well as earliest times of availability. The model takes into account such physical and temporal considerations, and also accounts for the need for additional power generation to compensate for energy loss penalties resulting from the capture of CO2. A case is used to demonstrate the application of the proposed model. Sensitivity analyses are carried out to examine the tradeoff between carbon emissions reduction and power cost, as well as the effects of uncertainties in sink characteristics and properties of compensatory power on CCS.
Article
Much of the previous research on carbon capture and storage (CCS) has focused on individual technologies for disposing of CO2, such as capture, storage, sequestration, or transport. Moreover, recent research work considers utilization of CO2 as fuels, chemicals, or nutrients for bioreactors. To efficiently manage CO2 and the economic benefits achieved by this process, the CO2 transport and processing infrastructure supporting CCS will have to be constructed at a macro-scale. This paper introduces a scalable and comprehensive infrastructure model for CO2 utilization and disposal that generates an integrated, profit-maximizing CCS system. The proposed model determines where and how much CO2 to capture, store, transport, utilize or sequester to maximize total annual profit while meeting the CO2 mitigation target. The applicability of the proposed model is demonstrated using a case study for treating CO2 emitted by an industrial complex on the eastern coast of Korea in 2020. The results may be important in systematic planning of a CCS infrastructure and in assisting national and international policy makers to determine investment strategies for developing CCS infrastructures.
Article
A novel energy and cost effective transport chain for stranded natural gas utilized for power production with CO2 capture and storage is developed. It includes an offshore section, a combined gas carrier and an integrated receiving terminal. The combined carrier will transport liquid carbon dioxide (LCO2) and liquid nitrogen (LIN) outbound, where natural gas (NG) is cooled and liquefied to LNG by vaporization of LIN and LCO2 onboard the carrier. The same carrier is used to transport the LNG onshore, where the NG can be used for power production with CO2 capture. The combined carrier consists of 10 cylindrical tanks with a diameter of 9.2 m and varying lengths from 14 to 40 m. The total ship volume is 13,000 m3. Assuming 85% capture rate of the CO2, the maximum ship utilization factor (SUF) is 63.4%. Due to the combined use of the storage tanks, the SUF is decreased with 1.4% points to 62%. The ship is equipped with a bi-directional submerged turret loading for anchoring and loading of NG and unloading of CO2. Two ships can deliver NG to and remove CO2 from a 400 MWnet power plant, and still obtain continuous production of LNG offshore without intermediate storage. The investment cost for each gas carrier is 40 million EUR giving total transport cost of 16.9 EUR/tonne LNG. The cost for the offshore transfer system is 6.6 million EUR per tonne LNG, whereas the cost for onshore storage and loading system is 3.1 and 0.8 million EUR per tonne LNG, respectively. The total specific costs for the ship transport, including onshore storage, loading shipping and offshore unloading are 27.5 EUR per tonne LNG for a roundtrip of 5 days, including voyage, production of LNG, unloading, connecting and berthing.
Article
Carbon dioxide capture and storage (CCS) involves the capture of CO2 at a large industrial facility, such as a power plant, and its transport to a geological (or other) storage site where CO2 is sequestered. Previous work has identified pipeline transport of liquid CO2 as the most economical method of transport for large volumes of CO2. However, there is little published work on the economics of CO2 pipeline transport. The objective of this paper is to estimate total cost and the cost per tonne of transporting varying amounts of CO2 over a range of distances for different regions of the continental United States. An engineering-economic model of pipeline CO2 transport is developed for this purpose. The model incorporates a probabilistic analysis capability that can be used to quantify the sensitivity of transport cost to variability and uncertainty in the model input parameters. The results of a case study show a pipeline cost of US$ 1.16 per tonne of CO2 transported for a 100 km pipeline constructed in the Midwest handling 5 million tonnes of CO2 per year (the approximate output of an 800 MW coal-fired power plant with carbon capture). For the same set of assumptions, the cost of transport is US$ 0.39 per tonne lower in the Central US and US$ 0.20 per tonne higher in the Northeast US. Costs are sensitive to the design capacity of the pipeline and the pipeline length. For example, decreasing the design capacity of the Midwest US pipeline to 2 million tonnes per year increases the cost to US$ 2.23 per tonne of CO2 for a 100 km pipeline, and US$ 4.06 per tonne CO2 for a 200 km pipeline. An illustrative probabilistic analysis assigns uncertainty distributions to the pipeline capacity factor, pipeline inlet pressure, capital recovery factor, annual O&M cost, and escalation factors for capital cost components. The result indicates a 90% probability that the cost per tonne of CO2 is between US$ 1.03 and US$ 2.63 per tonne of CO2 transported in the Midwest US. In this case, the transport cost is shown to be most sensitive to the pipeline capacity factor and the capital recovery factor. The analytical model elaborated in this paper can be used to estimate pipeline costs for a broad range of potential CCS projects. It can also be used in conjunction with models producing more detailed estimates for specific projects, which requires substantially more information on site-specific factors affecting pipeline routing.
United Nations Environment Programme, World Meteorological Organization, Intergovernmental Panel on Climate Change
  • O Ipcc
  • R Edenhofer
  • Y Madruga
  • Sokona
IPCC, O. Edenhofer, R. Pichs Madruga, Y. Sokona, United Nations Environment Programme, World Meteorological Organization, Intergovernmental Panel on Climate Change, Potsdam-Institut für Klimafolgenforschung (Eds.), Renewable Energy Sources and Climate Change Mitigation: Special Report of the Intergovernmental Panel on Climate Change, Cambridge University Press, New York, 2012.
Potential for biomethane and biohydrogen production in Finland (finnish: Biometaanin ja -vedyn tuotantopotentiaali Suomessa)
  • H Tähti
  • J Rintala
H. Tähti, J. Rintala, Potential for biomethane and biohydrogen production in Finland (finnish: Biometaanin ja -vedyn tuotantopotentiaali Suomessa), University of Jyväskylä, Jyväskylä, Finland, 2010.
International Flame Research Foundation, Suomen kansallinen osasto
  • R Raiko
R. Raiko, International Flame Research Foundation, Suomen kansallinen osasto, Poltto ja palaminen, Teknillistieteelliset akatemiat, Helsinki, 2002.
Population Projection 2015 According to Age and Sex by Area
Statistics Finland, Population Projection 2015 According to Age and Sex by Area 2015 -2040, 2016.
Carbon Sources for Power-to-Gas Applications in the Finnish Energy System
  • A Holopainen
A. Holopainen, Carbon Sources for Power-to-Gas Applications in the Finnish Energy System, mSc Thesis, 2015.