This study presents a techno-economic assessment of an amine-based carbon capture technology. The aim is to compare different methods to evaluate the cost effect of doubling the capacity. A base case was established in Aspen HYSYS with 15 m absorber packing height, 6 m desorber packing height, removal efficiency of 85 % and a heat exchanger minimum temperature approach (ΔTmin) of 10 °C. Then dimensioning and cost estimation was carried out using Aspen HYSYS spreadsheets to automatically calculate CAPEX, OPEX and carbon capture cost per ton CO2 captured. To estimate the Bare Erected Cost (BEC), the Enhanced Detailed Factor (EDF) and the Aspen Process Economic Analyzer (APEA) were employed. The EDF method determines the installation cost of each piece of equipment, while the Nazir-Amini method only offers the Total Plant Cost (TPC). Applying the EDF method, the TPC for the base case, the doubled feed gas case and the two-absorber case were calculated to 76, 141 and 150 MEuro respectively. The estimated annual OPEX for the base case was 42.5 MEuro, while for the two alternatives the OPEX was very close to the double of the base case. The estimated carbon capture cost for the base case, two-absorber case, and double feed gas scenario were 52.4 €/ton, 51.8 €/ton, and 50.5 €/ton, respectively. The study demonstrates that a combination of Aspen HYSYS simulation, APEA and the EDF method is an effective method to evaluate different alternatives for increasing the capacity.

A combined rich and lean vapour compression configuration was investigated for CO2 capture from a cement plant. This was to assess its performance in energy consumption, actual CO2 emission reduction, and cost reduction potentials compared with the conventional process and the simple rich vapour compression and lean vapour compression configurations. Two electricity supply scenarios were considered: from natural gas combined cycle power plant and a renewable source like hydropower. The three vapour compression configurations outperformed the standard CO2 absorption configuration in energy requirement, actual CO2 emissions reduction and in CO2 avoided cost reduction. The best performance was achieved by the combined rich and lean vapour compression configuration. The reboiler heat, equivalent heat and CO2 avoided cost reduction performance was 24 - 30 %, 16-18 % and 13 - 16 % respectively. However, the performances in energy, CO2 emissions reduction and CO2 avoided cost are only marginally better than the lean vapour compression configuration. The use of renewable electricity, like hydropower electricity will help CO2 capture processes to achieve higher CO2 emission reduction and lower CO2 avoided cost compared to fossil fuel based electricity.

The performance of a plate heat exchanger (PHE), in comparison with the conventional shell and tube types, through a trade-off analysis of energy cost and capital cost resulting from different temperature approaches in the cross-exchanger of a solvent-based CO2 capture process, was evaluated. The aim was to examine the cost reduction and CO2 emission reduction potentials of the different heat exchangers. Each specific heat exchanger type was assumed for the cross-exchanger, the lean amine cooler and the cooler to cool the direct contact cooler’s circulation water. The study was conducted for flue gases from a natural-gas combined-cycle power plant and the Brevik cement plant in Norway. The standard and the lean vapour compression CO2 absorption configurations were used for the study. The PHE outperformed the fixed tube sheet shell and tube heat exchanger (FTS-STHX) and the other STHXs economically and in emissions reduction. The optimal minimum temperature approach for the PHE cases based on CO2 avoided cost were achieved at 4 °C to 7 °C. This is where the energy consumption and indirect emissions are relatively low. The lean vapour compression CO2 capture process with optimum PHE achieved a 16% reduction in CO2 avoided cost in the cement plant process. When the available excess heat for the production of steam for 50% CO2 capture was considered together with the optimum PHE case of the lean vapour compression process, a cost reduction of about 34% was estimated. That is compared to a standard capture process with FTS-STHX without consideration of the excess heat. This highlights the importance of the waste heat at the Norcem cement plant. This study recommends the use of plate heat exchangers for the cross-heat exchanger (at 4–7 °C), lean amine cooler and the DCC unit’s circulation water cooler. To achieve the best possible CO2 capture process economically and in respect of emissions reduction, it is imperative to perform energy cost and capital cost trade-off analysis based on different minimum temperature approaches.

The paper provides an analysis of the potential development of a CCS-hub in the port of Gothenburg, Sweden, including technoeconomic assessments of different transport modes to the port (barges, truck, train) as well as storage and utilities requirements at the individual facilities and in the port. The city of Gothenburg is particularly interesting seen from a Swedish CCS perspective with port facilities and reasonable location to Danish and Norwegian storage sites and with multiple fossil and biobased emission sources located less than 150 km away.The work shows that train could be a potential cost-efficient intermediary transport mode to the port for several of the sources located 100 to 200 km away. Transport from the port to the storage location, which is assumed to be in Norway or Denmark, will most likely be by ship in the medium term. Transport cost from the port can be reduced substantially through utilization of larger ships transporting CO2 from multiple sources. Transporting the CO2 to storage in Danish reservoirs, particularly on the Danish east coast, will reduce cost not only for the transport part but also for intermediate storage when compared to transport to Norwegian reservoirs due to the considerably shorter transport distance. Transport by pipeline to reservoirs on the Danish east coast can be a potential option in the longer term further reducing the cost for intermediate storage.

The scope of the CO2LOS II project has been to reduce the cost of CO2 ship transportation by utilizing new technology and investigating optimization possibilities in the logistic chain. Capture and storage are outside the battery limits for the project.The project has focused on conceptual engineering of different parts of the logistics chain, covering a wide variety of choices. The intention has been to fill up a tool-box to be used for future CCS logistics. Relevant choices have been visualized in a high-level schematic drawing, the CO2LOS II tool-box. A special emphasis has been laid on low pressure transport, reduced GHG emissions from ship operations and exploring the concept of offshore unloading. TRL and cost evaluations has been performed as an integral part of the project.Neither is it possible, nor has it been the target of the project to find one optimal technical solution for a CCS ship logistics chain. The technology to be used will have to be selected from the tool-box when the frames of the CCS project is known, such as capture volumes, capture and storage location, characteristics of the reservoir, etc. Acknowledging this, the documented methodology used, including logistics, simulations, calculations, analysis, results from discussion with partners and vendors, and literature studies are as important as the developed concepts.

In a CCS chain, the CO2 is first captured and then transported to a suitable permanent storage site. The transport element could either be by pipeline, ship, or a combination of both, and the choice of transportation strategy will depend on several factors. Such as location of emission source, location of suitable storage sites and the volume of CO2 to be transported. In the ongoing Norwegian Longship project, the transport concept under planning is shipping of CO2 from one or two emission sites to an import hub located at Kollsnes, Norway. From Kollsnes, the CO2 is to be transported to an offshore aquifer through a pipeline. The scope of the ongoing project ''CO2LOS II'' (CO2 Logistics by Ship Phase II) is to reduce the cost of CO2 ship transportation by utilizing new technology and investigate optimization possibilities in the logistic chain. The project focuses on all activities between capture and permanent storage. Within this setting, this article encompasses a qualitative/quantitative assessment of greenhouse gas (GHG) emissions from the transport chain. This associated GHG emission is expected to be significantly lower than the quantities of CO2 stored, still it is worthwhile to estimate.The investigation has shown that it is the electricity consumption of the CO2 liquefaction plant that is the major contributor of GHG emissions from the transport chain followed by the fuel consumption of the ship, while the CO2 boil-off from intermediate storage tanks and the ship's cargo tanks is not a major contributor to the emissions in the transport chain. Therefore, the effort should be to reduce the fuel or power consumption or to change the fuel type to a lower carbon intensive fuel or power mix.

The industrial deployment of amine-based CO2 capture technology requires large investments as well as extensive energy supply for desorption.Therefore, the need for efficient cost and economic analysis aimed at CO2 capture investment and operating costs is imperative.Aspen HYSYS simulations of an 85% CO2 absorption and desorption process for flue gas from cement industry, followed by cost estimation have been performed.This is to study the cost implications of different plants options.Each plant option has a different lean/rich heat exchanger type.Cost optimisation of the different heat exchangers is also done in this work.Three different shell and tube and two plate and frame heat exchangers have been examined.The minimum CO2 capture cost of €57.9/tonCO2 is obtained for a capture plant option having a gasketed-plate heat exchanger with ∆ min of 5 ℃ as the lean/rich heat exchanger.The use of plate and frame heat exchangers will result in considerable CO2 capture cost reduction.

Reducing the cost of CCS is necessary to achieve a cost point that encourages its large-scale deployment. In this work, we have evaluated if the second generation solvent CESAR1 (a blend of AMP (2-amino-2-methyl-1-propanol) and piperazine) can be established as the new state-of-the art benchmark solvent system, replacing monoethanolamine (MEA). We provide cost estimates for the integration of MEA and CESAR1 in selected reference cases that are representative of power (lignite-fired Power plant) and industrial (Waste to Energy and Cement) processes. The findings reported here do not indicate that CESAR1 (or AMP/PZ blends) should be used as the updated benchmark for post-combustion CO2 capture. It seems fair to assume that both MEA and CESAR1 can be cost-competitive solutions, and the decision to use either of them should be taken case by case, with CESAR1 possibly being a preferable solution in case the heat availability is a limiting factor, or the heat costs are high. For more reliable results, and a clear differentiation between MEA and CESAR1, cost estimations should take emission and degradation countermeasures into account. Additionally, more experimental data from long-term pilot testing campaigns is needed to further quantify the solvent replacement rates in terms of volatile emissions and degradation rates. Only then, a fairer comparison between the two solvent systems could be established.

This paper describes a design and pre-feasibility study of a multi-user intermediate CO2 storage facility in the Grenland region of Norway considering upstream and downstream issues. The study focuses on the principles for design and installation of a generic hub facility, so the results can be utilised at other sites. The pre-feasibility study found that design pressures of 7 and 15 bar pressures are feasible transport conditions; moreover, showed that economies of scale might reduce the total cost for a CO2 network. It is recognised that cooperation across the chain is crucial in the management of impurities, due to the likely diverse sources of CO2 stream composition. An intermediate storage facility can support the continuous supply of CO2 via a pipeline system for reservoir injection, therefore improving the integrity of the injection well and equipment and the reservoir performance. A mixed integer linear programming optimisation model has been developed for sizing and costing two intermediate storage HUBs of CO2 in Grenland and Kollsnes and shipping connection between them. The model considers a flow of 2 mtpa of CO2 for 27 years. The 7 bar design pressure has shown lower total costs when compared with the 15 bar scenario. This is due to the higher costs for shipping and intermediate storage when operating at higher pressure, which is larger than the cost reduction from liquefying CO2 to a higher pressure and higher temperature than those required for a 7 bar scenario. The estimated levelised costs were 11.7 €/tonne at 7 bar pressure and 13.2 €/tonne at 15 bar pressure.

A standard method to remove CO2 is by absorption in monoethanol amine (MEA) followed by desorption.A traditional aim has been to find the process parameters which give the lowest combined investment and operating cost.The aim in this work is to calculate cost optimum process parameters and evaluate whether it is possible to perform automated cost estimation and optimization.Aspen HYSYS simulations of a standard amine based process for CO2 capture from a cement plant have been performed.The capital cost of CO2 capture was estimated based on equipment cost from Aspen In-plant cost estimator and a detailed factor method.Operating cost included electricity, heat consumption and maintenance.Optimum temperature difference in the main heat exchanger was calculated to 13 °C after one simulation for each temperature.The lowest calculated cost was achieved with 12 stages (meter packing height) based on one simulation for each stage number.With improved robustness of the simulations, it should be possible to optimize the temperature difference in one automated calculation.To optimize the height of the absorption colum n automatically, a way to update the number of stages during the simulations has to be found.

After the CO2 has been captured, it must be transported to permanent storage to complete the CCS chain. The configuration of the chain, choice of capture technology, transport method and storage site) will vary from case to case. In this study, the CO2 is captured in Rotterdam, Netherlands, and transported to an import hub at Kollsnes on the west coast of Norway by shipping. The site from which the CO2is transported from is the export terminal, and encompasses the CO2 liquefaction, intermediate storage tank facility, and loading installation. Of these, especially the intermediate storage tank will be area demanding and could pose a challenge in cases where there is limited land area available, or the land purchase cost is high. Three different export terminal configurations have been investigated: onshore, combination of onshore and offshore, and offshore floating terminal. The investigation shows that there is potentially a high degree of flexibility regarding export terminal configuration as all three configurations are feasible. On sites where a fully onshore terminal is not possible other solutions are available. In the case of a fully offshore/near shore terminal parallels can be drawn to the LNG supply chain where floating processing terminals are gaining interest as it is reported to have several attractive advantages including lower cost and construction time.

Capital cost is frequently estimated for new and retrofit carbon capture plants as new concepts for cost reduction emerge. Capital cost during initial cost estimation of chemical plants strongly depends on the installation factor (s) of the methodology employed. How these installation factors respond to the cost of each equipment determines the total plant cost and the type of capital cost (new plant or modification project) each method is suited for. The effect of equipment installation factors on capital cost of an amine-based CO2 capture plant using the Enhanced Detailed Factor (EDF) method has been studied. Plant construction characteristic factors have also been introduced to account for different plant construction characteristic situations. The impacts of the installation factors of seven methodologies on capital cost were compared. A uniform installation factor will likely lead to overestimation of very expensive equipment and underestimation of less expensive equipment. EDF method's installation factors respond based on each equipment cost. Even though all the methods estimated the optimum Delta T-min in the cross-exchanger to be 15 degrees C, the cost estimated was (sic)66/tCO(2) by the EDF method, Smith's percentage of delivered-equipment factorial method and Hand's factorial method; and (sic)69-79/tCO(2) by the other methods. The results demonstrate that the EDF method is suitable for estimating capital cost for new plants and modification projects, small and large plants, and accounts for different plants' situations.

The work presented in this paper is related to assessment and benchmarking of a MOF based membrane technology for application of carbon capture in a cement plant and has been conducted in the ongoing H2020 project GENESIS Two alternatives for a two-stage membrane-based process were established and simulated in Aspen Plus while a generic crossflow model of the membrane was developed and implemented in Aspen Custom Modeler. As a reference case for the benchmarking a conventional absorber/stripper configuration with 30wt% MEA as solvent was used. For the cost calculation the Aspen In Plant Cost Estimator (AIPCE) tool combined with an in-house tool were used and the assessment criteria were the Specific Primary Energy Consumption for CO2 Avoided (SPECCA) and the cost of CO2 avoided. The determined SPECCA for both the membrane alternatives are similar, but approximately half of the SPECCA for the reference case. Since the cost of the membrane is highly uncertain, a sensitivity analysis was performed, but it turned out that only one of the membrane process alternatives with the lowest membrane cost outperforms the reference case related to avoided cost. Though the OPEX costs are promising for four of the membrane cases, capital costs are high for all membrane cases. These results are based on a specification of 90% capture rate and at least 95% purity of the separated CO2.

In Norway, the full-scale project Longship will capture CO2 from one or two sources, transport the CO2 by ship to a hub at Kollsnes, where the CO2 is heated and pumped before transported by a pipeline to an offshore storage site. It is likely that other CO2 sources in Norway will adopt the same transport strategy, i.e., transport of captured CO2 from the capture site to the hub at Kollsnes before being transported in a common pipeline to permanent storage. In this paper, the results of an investigation into CO2 ship transport configurations for CO2 sources located in the Nordland County in Norway is presented. Five regional hub locations have been identified, each serving one or more emission sources. These regional hubs are then connected to the Kollsnes hub via ship transport. Each regional hub will be different and are sized according to the CO2 volumes to be transported. There could be many suitable shipping configurations based on the ship size and number of ships used for the operations. Six shipping configurations have been described and cost estimated. The configuration where each regional hubs is served by a dedicated ship, is according to the results the most cost effective alternative. It has the lowest CAPEX and an OPEX in line with the other configurations. The ships are specifically sized according to the CO2 volume at each regional hub. This configuration is also attractive as it does not depend on the readiness of the other hubs as they are operated independently of each other.

We examined the cost implications of selecting six different types of heat exchangers as the lean/rich heat exchanger in an amine-based CO2 capture process. The difference in total capital cost between different capture plant scenarios due to the different costs of the heat exchangers used as the lean/rich heat exchanger, in each case, is in millions of Euros. The gasketed-plate heat exchanger (G-PHE) saves significant space, and it saves considerable costs. Selecting the G-PHE instead of the shell and tube heat exchangers (STHXs) will save €33 million–€39 million in total capital cost (CAPEX), depending on the type of STHX. About €43 million and €2 million in total installed costs (CAPEX) can be saved if the G-PHE is selected instead of the finned double-pipe heat exchanger (FDP-HX) or welded-plate heat exchanger, respectively. The savings in total annual cost is also in millions of Euros/year. Capture costs of €5/tCO2–€6/tCO2 can be saved by replacing conventional STHXs with the G-PHE, and over €6/tCO2 in the case of the FDP-HX. This is significant, and it indicates the importance of clearly stating the exact type and not just the broad classification of heat exchanger used as lean/rich heat exchanger. This is required for cost estimates to be as accurate as possible and allow for appropriate comparisons with other studies. Therefore, the gasketed-plate heat exchanger is recommended to save substantial costs. The CO2 capture costs of all scenarios are most sensitive to the steam cost. The plate and frame heat exchangers (PHEs) scenario’s capture cost can decline from about €77/tCO2 to €59/tCO2 or rise to €95/tCO2.

The estimates of post combustion CO2 capture costs reported in the literature range from 50 (sic)/tCO(2) to 128 (sic)/tCO(2), reflecting differences in the cost estimation methods used, scopes of the analyses, and assumptions made. This variation in calculated costs is important when evaluating the feasibility of a technology and highlights the importance of ensuring consistency and transparency in cost estimations. This study establishes a cost estimation tool that highlights the effects of different assumptions on the overall cost of a capture plant and identifies the crucial technical and economic factors. The input is a simplified process flow diagram and equipment list. Detailed installation factors and the equipment cost are the two main elements used to derive the capital expenditures (CAPEX), which represent a fundamental component of the cost estimation approach. A detailed installation factor sheet is used for the capital cost estimation. The method is applied to a Base case that involves the capture of CO2 from the flue gas of a process industry, giving a capture cost of 62.5 (sic)/tCO(2). The Base case results reveal that the steam cost, electricity cost, and capital cost are the main contributors. This method can provide an overview of the main cost drivers, and a sensitivity analysis of the variable input parameters can be performed simply and quickly. The results obtained using this method can be valuable in the early phase of the project and contribute to decision making.

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A tecno-economic investigation into coupling two CO2 capture technologies, post-combustion MEA scrubbing and oxycombustion, to a cement plant under different scenarios was undertaken. The results show that with the assumptions made that oxy-combustion could be a promising technology. However, it has a considerable higher degree of coupling with the cement plant than post-combustion technologies. Due to this higher degree of uncertainty in retrofitting oxy-combustion to an existing cement plant it is believed that this technology is not applicable in the near future. Still, gradual modification of the cement plant during major revamps could reduce the risks, cost, and speed of implementation. The two major elements of oxy-combustion are electricity consumption and the complexity of modifications to the cement plant. A sensitivity analysis was performed were the cost of these two elements were doubled. For MEA scrubbing one of the major cost drivers is the steam consumption. The benefit of utilizing waste heat recovered from the cement plant is considerable. In addition, an effort was made to include the origin of CO2 for the cement plant fuel, electricity consumed, and onsite steam generation. To identify the actual fossil CO2 capture rate and the cost implication this has on the scenarios investigated.