CCS Costs Research Articles

Development of the decision-support tool ‘Harvest Mate’: economic calculations

Improvements in sugarcane-harvesting practices remain critically important for productivity, profitability and sustainability gains in the Australian industry. Developing a decision-support tool to guide economically optimum harvester settings could add AUD44mn to grower revenue. The online ‘Harvest Mate’ (HMate) tool was developed to reduce green sugarcane-harvesting losses and improve economic returns for growers. The ‘Harvest Mate’ tool includes setting-up an online user profile for initial data capture that enables users to assess the most profitable harvester settings (e.g., flow rate and extractor fan speeds) infield. HMate can estimate harvesting cost changes and guide pre-season contract rate negotiations between the contractor and grower. The economic component of HMate incorporates both variable and fixed cost inputs, allowing the overall net benefit/loss to be determined for the grower. The highest net benefit output is defined as the most economically optimal harvester setting, accounting for the cost of harvesting and revenue achieved. HMate economic estimates show a high level of predictive accuracy for the cost/ha, cost/t and net benefit obtained when compared to actual detailed harvesting group costings. Slight differences were identified in the predicted cost/h results for HMate due to improvements in labour and fuel calculations. Information entered by users allows the selection of the most profitable harvester settings for each unique situation that accounts for yield, CCS, and harvesting costs.

Economic Analysis of an Integrated Steel Plant Equipped with a Blast Furnace or Oxygen Blast Furnace

The oxygen blast furnace with top gas recycling (TGR-OBF) ironmaking technology can reduce CO2 emissions, especially when combined with carbon capture and storage technology (CCS). However, the successful commercialization of technology cannot be achieved without economic evaluation. This study applied the Box–Behnken design method and a Monte Carlo simulation-based risk analysis to assess the sensitivity of influencing factors affecting the net present value (NPV) of an integrated steel plant (ISP) and to predict the impact of variable market scenarios on the NPV of three ISPs. The results indicated that among the three ISPs, the conventional ISP (C-ISP) is the least profitable, followed by the ISP equipped with TGR-OBF and CCS (ISP-OBF-CCS), and the most profitable is the ISP equipped with TGR-OBF (ISP-OBF), which is at least CNY 0.392 Bn and CNY 1.934 Bn more profitable than the ISP-OBF-CCS and C-ISP respectively. Under the current Chinese carbon trading policy and the cost of CCS, CCS technology does not make a company profitable. This study explored an approach for analyzing ISP economic applicability under uncertain markets, which can be used as a reference for the development of alternative processes for steel production.

The cost of CCS - a product chain analysis of the cement and pulp industries

The cost of CCS - a product chain analysis of the cement and pulp industries

Process Integration of Advanced Amine-based Solvents in Power and Industrial Plants: A New Benchmark for Post-combustion Carbon Capture?

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.

Capture and Compression Process of the Tomakomai Ccs Demonstration Project

The Tomakomai CCS Demonstration Project was launched in April 2012 by the Ministry of Economy, Trade and Industry (METI), aiming for the practical use of CCS in Japan by around 2020. It required 4 years for EPC work of the demonstration facilities and CO2 injection was started on April 6, 2016. On November 22, 2019, the project achieved the target of 300,000 tonnes of cumulative injection and injection was terminated, whereas monitoring operations are being continued. Many important results were obtained through the demonstration, and those regarding capture and compression processes are summarized as follows: • The capture process of the Tomakomai demonstration consists of an absorber, a stripper and a low-pressure flash tower with the absorber having a dual function of bulk absorption (lower part) and lean absorption (upper part). This process configuration, called a two-stage absorption process, achieved an average amine reboiler heat of 0.9 GJ/t-CO2, which is 1/2 to 1/3 of a conventional one stage absorption process that ranges from 2 to 3 GJ/t-CO2. Furthermore, process simulation studies of an “innovative process layout” suggested that the amine reboiler heat could be reduced to 0.487 GJ/t-CO2, which is 1/4 to 1/6 of the conventional heat requirement. • The CO2 control system of two serial compressors which increases the pressure of captured CO2 up to 9.7 MPaG was able to achieve fully automatic control against periodic fluctuation of the CO2 flow rate after modification. The pressure of the captured CO2 (50 kPaG) upstream of the CO2 compressors could be stabilized; consequently, the CO2 flash of the low-pressure flash tower could also be stabilized, • It was verified that the pressure control of the captured CO2 is very important in maintaining the steady flash effect of the low-pressure flash tower and subsequent stable performance of the bulk absorption in the absorber. • The CO2 partial pressure of the absorber inlet was adjusted to conditions similar to those of a hydrogen production unit (HPU), ammonia production unit (APU) and integrated coal gasification combined cycle (Air Blown IGCC). The low amine reboiler heat obtained by the two-stage absorption process and the innovative process layout have the potential to be applicable to these processes, and greatly reduce the fuel cost as well as the corresponding avoided cost of CCS.

Value of Emerging and Enabling Technologies in Reducing Costs, Risks and Timescales for CCS

A range of digital and enabling technologies are already helping the energy sector, as well as others, to reduce costs, risks and timescales for projects. The pace of development and adoption of these technologies is growing rapidly, and digitalisation is expected to deliver significant improvements in energy systems in the coming years. Many of the applications of digital technologies are expected to be transferable to CCS but the implications of these technologies for CCS have not previously been fully investigated or quantified. Through a horizon scanning exercise, this study aimed to understand the relevance of digital and enabling technologies for CCS and assess the benefits that they could offer to large-scale CCS deployment. A wide range of emerging and enabling technologies were considered, including: Robotics, drones and autonomous systems; Novel sensors; Digital innovations such as Artificial Intelligence, Internet of Things and blockchain; Virtual reality and augmented reality (VR/AR); Additive manufacturing; Nanomaterials and composites. Digital and enabling technologies offer a range of benefits to projects, including improved process efficiency, improved decision-making, and improved durability of components. Many of the applications and associated benefits of these technologies for CCS are likely to be similar in nature to those experienced in the energy and oil and gas sectors. In addition, several applications of digital and enabling technologies are already being developed for CCS, specifically: subsurface sensing techniques, robotics and environmental sensing for storage site monitoring, machine learning for materials discovery, and additive manufacturing of capture technology components. The benefits of digital and enabling technologies are projected to be realised gradually, with little cost savings accessible to projects beginning operation within the next 5 years (2025) but greater cost savings available from 2030 and out to 2040. This reflects both the current maturity level of the relevant technologies and the development timescales of CCS projects. While a large proportion of CCS costs are due to capex, the majority of applications of digital and enabling technologies affect opex; therefore only modest savings in base project costs (capex, opex and fuel) are projected. However, reflecting the value of the benefits offered by many of the digital and emerging technologies, more significant cost reductions across the chain are projected to be in cost components associated with facility downtime (due to planned or unplanned maintenance) and supply chain losses of CO2. Across the CCS chain, the largest absolute cost savings ($/tCO2) are projected for capture plants, with the largest relative cost savings (%) for storage sites. On a global scale, total cumulative savings of close to $200bn (10%) in lifetime costs of projects can be possible. Aside from cost, a number of technical, political and economic challenges are limiting large-scale CCS deployment. The main risks of relevance to applications of digital technologies are expected to be related to technical viability, although some political and financial barriers may also be addressed through technologies that increase confidence in projects. For example, intelligent modelling and improved sensing techniques and procedures may improve confidence in prediction of storage site performance (injectivity and capacity) and improved confidence in CO2 storage as a long-term solution through improved monitoring. Based on current technology developments, timescales for global CCS deployment are not expected to be significantly reduced by the introduction of digital and enabling technologies. However, it is possible that disruptive developments not foreseen here may become relevant in future.

Towards Improved Cost Evaluation of Carbon Capture, Transport and Storage From Industry

This paper briefly summarises the development of improved guidelines for cost evaluation of carbon dioxide capture, transport and storage (CCS) from industrial applications [1] building on previous work in the field. It discusses key challenges and factors that have a large impact on the results of cost evaluations but are often overlooked or insufficiently addressed. These include cost metrics (especially in the context of industrial plants with multiple output products), energy supply aspects, retrofitting costs, CO2 transport and storage, and maturity of the capture technology. Where possible, examples are given to demonstrate their quantitative impact and show how costs may vary widely on a case-by-case basis. Recommendations are given to consider different possible heat and power supply strategies, as well as future energy and carbon price scenarios, in order to better understand CCS costs under various conditions. Since retrofitting CCS is especially relevant for industrial facilities, further recommendations are made on how to better account for the key elements that constitute retrofitting costs. Furthermore, instead of using a fixed unit cost for CO2 transport and storage, cost estimates should at least consider the CO2 flowrate, transport mode, transport distance and type of storage, to obtain more realistic cost estimates. Recommendations are also given on factors to consider when assessing the technological maturity level of CCS in various industrial applications, which is important when assessing cost contingencies and uncertainties. Lastly, we urge techno-economic analysis practitioners to clearly report all major assumptions and methods, as well as comprehensively examine the impact of uncertainties on their cost estimates.

Impact of Uncertainties on the Design and Cost of CCS From a Waste-to-Energy Plant

Uncertainties are an inherent and important element of novel systems with limited large-scale industrial experience and must be taken into account in order to enable the design of cost-efficient energy systems. This paper investigates the optimal design of carbon capture and storage from a waste-to-energy plant under uncertainties. With the aim of providing a better understanding of the impact of uncertainties on the design and cost of CCS chains, as well as the capture technology selection, the case of a hypothetical 40 MW waste-to-energy plant located in Norway is considered. The impact of key technical and cost uncertainties on the cost of different CO2 capture and CCS chain options are investigated using an in-house techno-economic CCS assessment tool combined with an uncertainty quantification framework. When the different capture options are compared on a deterministic basis, the advanced amine yields the best performances (CO2 avoidance cost of 153 €/tCO2,avoided), followed by the membrane process based on partial capture (200 €/tCO2,avoided) and MEA-based capture (217 €/tCO2,avoided). However, in contrast with the advanced amine, the partial capture considered in the membrane process does not enable net negative CO2 emissions. Once technical and cost uncertainties are taken into account, the advanced amine-based capture remains the best option, however the MEA-based capture outperform the membrane process. Finally, the stochastic optimisation showed that the uncertainties considered do not impact the optimal capture capacity in this case. The full CCS chain perspective is then included through two chain options: a nearby offshore saline aquifer or an offshore CO2 EOR storage located further away. The EOR-based chain leads to the best performances (187 vs. 202 €/tCO2,avoided) both on a deterministic basis and when different uncertainty scenarios are considered. However, as a shared transport and storage infrastructure is considered, uncertainty regarding the amount of CO2 coming from nearby industries leads to a different optimal design of the chain (pipeline diameter and ship capacity). Finally, uncertainties on the EOR response to CO2 injection can significantly reduce the potential of the CO2 EOR-based chain and lead to cases in which the saline aquifer-based chain would be optimal.

Best Practices and Recent Advances in Ccs Cost Engineering

Best Practices and Recent Advances in Ccs Cost Engineering

Exploring the Potential of CO2-EOR as a Mitigation Strategy in the Colombian Oil Value Chain

CCS is considered a primary strategy to curb CO2 emissions. In many models, CCS is an essential technology to meet the 2C target. Drastically reducing GHG emissions in the oil and gas industry will be needed to reach the 2C target as this industry is one of the five most energy and GHG intensive sectors. The implementation of CCS technologies has been widely studied for the refining stage of the oil value chain. According to Berghout et al., between 80 to 90% of GHG emissions in the refining industry could be reduced using CCS. However, the cost involved for its implementation, make it an unattractive pathway. CO2-EOR is currently a promising alternative to reduce CCS costs, and would be able to produce an oil with low-associated emissions during its recovery. This paper aims to estimate the techno-economic potential of CO2-EOR for reducing GHG emissions in the Colombian oil industry. For this purpose, the supply and demand of CO2 are studied by including the CO2 capture potential of the oil industry, cement, power generation and bioethanol, as well as the storage potential of CO2 through the oil recovery miscible process. The state-owned oil company Ecopetrol S.A. was taken as a case study, which represents the oil value chain in Colombia, with about 70% of crude oil produced and 100% of oil transported and refined in the country. A total of 193 Mt CO2 between 2025 and 2040 could be stored through CO2-EOR. As the projected emissions of the oil and gas industry in Colombia from 2010 to 2040 are estimated at 570 Mt CO2, this is equivalent to a potential 34% reduction in CO2 emissions. This mitigation represents approximately 20% of the total reduction under the INDC target for the period 2025 to 2030.

Comparative analysis of transport and storage options from a CO2 source perspective

This study evaluated integrated CCS costs from the perspective of a CO2 source. A source will have captured CO2 requiring suitable storage and affordable transportation between source and storage. Capture, transport, and storage are the links of the CCS value chain. For this study, capture costs were modeled for six hypothetical sources (various industrial and power-generation facilities) with annual CO2 capture rates ranging from 0.65 to 3.90 million tonnes (Mt). Seven storage reservoirs located in the Appalachian, Illinois and Gulf Coast Basins—and of various quality with respect to CO2 storage—were modeled: two within the Rose Run Formation, three within the Mount (Mt.) Simon Formation, one in the Lower Tuscaloosa Formation, and one in the Frio Formation. Storage costs were calculated with the FE/NETL CO2 Saline Storage Cost Model for the seven selected storage reservoirs under dome and regional dip structural settings. For transportation, a dedicated pipeline system and a trunkline pipeline system were modeled. Transportation costs from source to storage reservoirs were evaluated using the FE/NETL CO2 Transport Cost Model. A source may not always be able to find suitable proximal storage. Low CCS costs reflect a source’s mass of captured CO2 finding suitable storage within an affordable transportation distance. Economies of scale are present in each link of the CCS value chain. These economies of scale are limited with respect to storage or the distance captured CO2 can be transported to storage.

Performance and cost of CCS in the pulp and paper industry part 2: Economic feasibility of amine-based post-combustion CO2 capture

The economic feasibility of retrofitting an amine based post-combustion CO2 capture process to an existing Kraft pulp mill and an existing integrated pulp and board mill has been assessed. This study builds on the technical assessment of the energy performance of the mills when retrofitting a post-combustion CO2 capture process by Onarheim et al. (2017).Between 75 to 100% of the CO2 emissions from the pulp and paper industry originate from the combustion of biomass. If the raw material is sourced sustainably, these emissions are categorized as carbon neutral. Applying sustainably managed biomass in the pulp and paper processes and capturing the resulting CO2 for permanent storage enables the industry to go carbon negative. In this study, the economic impact of retrofitting CO2 capture from the flue gases of the recovery boiler, the multi-fuel boiler and the lime kiln were assessed.The levelized cost of pulp and the cost of CO2 avoided were evaluated based on six different scenarios varying the CO2 tax, incentives for renewable electricity production, with and without recognizing biogenic CO2 emissions as neutral (exempting CO2 emissions from tax or not), and rewarding captured and permanently stored CO2 with negative emissions credit. Results show that the pulp and paper industry has a potential for realizing feasible implementation of large-scale industrial Bio-CCS. For cases where 60–90% of total site CO2 emissions are captured, the cost of avoided CO2 amounts to 52–66 €/t for the Kraft pulp mill and 71–89 €/t for the integrated pulp and board mill. The cost of avoided CO2, and thus the realization of Bio-CCS in the pulp and paper industry, is strongly dependent on prevailing policy frameworks such as the EU ETS. In order to reach a levelized cost of pulp similar to the reference mill without CO2 capture, a negative CO2 emission credit of 60–70 €/t CO2 for the Kraft pulp mill and 70–80 €/t CO2 for the integrated pulp and board mill will be required.As long as biogenic CO2 emissions that are captured and permanently stored are not recognized as negative and rewarded accordingly there is no economic incentive for the owners of pulp and paper mills to implement CCS. The only way to get the pulp and paper industry to implement and deploy Bio-CCS will need the support of the decision-makers in promoting the right policy framework and regulations to encourage the investment such as strong incentives for negative emissions which are bankable during the long term operation of the mills.

Australian Power Generation Technology APGT

The Australian Power Generation Technology (APGT) APGT delivers a technology neutral review of major large scale commercial power generation technologies for Australia. The technologies examined, among others, include: Carbon capture, transport and storage with key findings including:•To facilitate the implementation of CCS in Australia, one or more CO2 transport and storage networks need to be developed by 2030.•The cost for transport and storage of CO2 (excluding owner's and risk adjusted costs) from power plants in Australia is likely to vary from $5– 14/t CO2 to almost $70/t CO2.•Variations in factors such as operating conditions, engineering assumptions, material costs, topography and geological characteristics may lead to different costs. The integrated design of capture systems, transport routes, operating conditions and injection strategies may lead to lower costs.Learnings across all new power generation technologies including CCS will decrease costs to 2030.Intermittent renewables, energy storage systems, demand-side management schemes and high volume - high availability technologies such as coal and gas with CCS are likely. These technologies, working together will provide reliable electricity, 24/7 with a low environmental impact and an optimum overall cost of electricity.Through the levelised cost of electricity (LCOE), it is evident that a change of thinking around the cost of CCS needs to evolve. Consideration needs to be given to financing and policy options by government into the near future if CCS is to become a near-term reality. Furthermore, like current electricity grids, grids in the future will use a diverse mix of technologies as all technologies have arrange of more favourable and less favourable characteristics.

Preliminary Study on Policy Mix Effects on Economic Viability of Carbon Capture and Storage Project in Japanese Steel Industry

This paper explores policy mix effects on economic viability of CCS project in Japanese integrated steel plant. We conducted a Monte Carlo simulation under uncertainties of firm's capacity factor (pre-tax profit) and carbon price. The results indicate that tax credit (35 US$/tCO2) improve economic viability of CCS in the case of favorable business conditions. Subsidies for CCS costs improve economic viability of CCS even in the case of recessions; however, the subsidy effect is sensitive to carbon price. Tax credit could be one of key policy measures as a part of policy mix both for Japanese economy and CO2 mitigation.

Learnings from CO2CRC Capture Pilot Plant Testing – Assessing Technology Development

There have been many field carbon capture test facilities operated around the world over the last decade or so with a view to technology development and demonstrating and reducing capture cost to make CCS cost effective. A wide range of conventional and emerging technologies are undergoing tests by CO2CRC Limited (CO2CRC), using real feed gas from a variety of processes. Although learning by doing is the main motive for most of these tests, some went through systematic programs to step up the TRL ladder towards commercial readiness. This paper reports the results of each test facility to show the extent of learnings.

A techno-economic case study of CO2 capture, transport and storage chain from a cement plant in Norway

This paper investigates various alternatives for the application of CCS at a cement plant which is one of the focus site for CCS deployment in Norway. A matrix consisting of nine CCS alternative chains is analysed in order to quantify cost reduction potentials across the CCS value chain based on an in-house techno-economic assessment methodology and tool called iCCS. In particular, the paper quantifies the strong cost reduction potential of second generation capture technologies and transport technology selection. CO2 EOR is also identified to have a strong potential to reduce the overall CCS cost, however the cost benefits are strongly dependent on the oil value and the considered EOR injection period.The impact of the inclusion of CO2 capture and conditioning in the cost of cement shows that public financial support will be required to ensure that the plant remain competitive under current cement market price. Finally, comparison of the full-scale capture versus part-scale capture shows, in this case, that the economies of scale are nearly compensated by the additional steam cost, therefore limiting the interest for full-scale implementation. However, joint deployment with the two other CCS potential sites in Norway (Yara and Klemenstrud) may bring more synergies.

Offshore CCS and ocean acidification: a global long-term probabilistic cost-benefit analysis of climate change mitigation

Public fear over environmental and health impacts of CO2 storage, or over potential leakage of CO2 from geological reservoirs, is among the reasons why over the past decade CCS has not yet been deployed on a scale large enough so as to meaningfully contribute to mitigate climate change. Storage of CO2 under the seabed moves this climate mitigation option away from inhabited areas and could thereby take away some of the opposition towards this technology. Given that in the event of CO2 leakage through the overburden in the case of sub-seabed CCS, the ocean could function as buffer for receiving this greenhouse gas, instead of it directly being emitted into the atmosphere, offshore CCS could also address concerns over the climatic impacts of CO2 seepage. We point out that recent geological studies provide evidence that to date CO2 has been safely stored under the seabed. Leakage for individual offshore CCS operations could thus be unlikely from a technical point of view, if storage sites are well chosen, well managed and well monitored. But we argue that on a global longterm scale, for an ensemble of thousands or millions of storage sites, leakage of CO2 could take place in certain cases and/or countries for e.g. economic, institutional, legal or safety-cultural reasons. In this paper we investigate what the impact could be in terms of temperature increase and ocean acidification if leakage occurs at a global level, and address the question what the relative roles could be of on- and offshore CCS if mankind desires to divert the damages resulting from climate change. For this purpose, we constructed a top-down energy-environment-economy model, with which we performed a probabilistic Monte-Carlo cost-benefit analysis of climate change mitigation with on- and offshore CCS as specific CO2 abatement options. One of our main conclusions is that, even under conditions with non-zero (permille/year) leakage for CCS activity globally, both onshore and offshore CCS should probably – on economic grounds at least - still account for anywhere between 20 % and 80 % of all future CO2 abatement efforts under a broad range of CCS cost assumptions.

The role of flexible CCS in the UK's future energy system

That CCS will be required to operate in a flexible and load following fashion in the diverse energy landscape of the 21st century is well recognised. However, what is less well understood is how these plants will be dispatched at the unit generator scale, and what effect this will have on the performance and behaviour of the plant at the individual unit operation level. To address this gap, we couple an investment and unit commitment energy system model with a detailed plant-level model of a super-critical coal-fired power station integrated with an amine-based post-combustion CO2 capture process. We provide insight into the likely role of coal and gas CCS plants in the UK's energy system in the 2030s, 2040s and 2050s. We then evaluate the impact that this has on the performance of an individual coal CCS plant operating in this system, and chart its evolution throughout this period. Owing to the increased frequency and duration of part-load operation, asset utilisation and average efficiency suffer, leading to a substantially increased LCOE, implying that CCS costs will need to decrease more rapidly than is currently expected. Further, as a direct consequence of the dynamic operation, the interaction of the CCS plants with the downstream CO2 transport network is characterised by highly transient behaviour, including periods during which no CO2 is injected to the transport network, implying that the transport system must therefore be designed to incorporate this variability of supply.

Comparative techno-economic assessment of biomass and coal with CCS technologies in a pulverized combustion power plant in the United Kingdom

The technical performance and cost effectiveness of white wood pellets (WWP) combustion in comparison to three types of coal namely U.S., Russian and Colombian coals are investigated in this study. Post-combustion capture and storage (CCS) namely with amine FG+, and oxy-fuel with carbon capture and storage (oxy-fuel) are applied to a 650MW pulverized combustion (PC) plant. The impacts of the Renewable Obligation Certificate (ROC) and carbon price (CP) policy in accelerating the CCS deployment in the framework of GHG emissions mitigation, are also evaluated. The operational factors affecting CCS costs and emissions in the power generation plants are taken into consideration, hence, the Integrated Environmental Control Model (IECM 8.0.2) is employed for a systematic estimation of plant performance, costs and emissions of different scenarios of fuel and CCS technologies.This study showed that the utilization of white wood pellets (WWP) in electricity generation can annually avoid about 3M tonnes CO2 emissions from a 650MW power plant. However, this mitigation process had impact on the plant efficiency and the cost of electricity. Further, the BECCS using white wood pellets has showed a better efficiency and lower cost of electricity with the oxy-fuel technology than the post-combustion CCS technology. However, in order to boost biomass energy CCS (BECCS) deployment with the WWP, an increase of the ROC for biomass power plants, or, an increase of the carbon price for the coal power plants is recommended. It was found that, the sensitivity of COE towards the ROC was higher than towards the carbon price variation. This result can be interpreted as the ROC has more positive impact than the carbon price, on the COE from the point of customers view without adding more burdens on the power generation companies.

Optimal pipeline design for CCS projects with anticipated increasing CO2 flow rates

Large-scale CCS projects with multiple CO2 sources will require large investments. Optimising the pipeline network design for cost reduction has been proposed as a potential way to reduce overall CCS costs. This paper presents a two-step methodology for the optimal design of on-shore pipelines with a projected increase in CO2 flow rate. The first step involves determining whether an oversized design is preferable over a duplicate pipeline design, on the basis of the levelised CO2 transport cost. This is performed through a simple correlation that depends on key parameters including the length of the pipeline, the timing and magnitude of the flow increase. If the oversized design is preferred, the second step of the proposed method determines the optimal diameter for the oversized pipeline. The approach, based on modelling of a wide range of generic cases, provides a two-step method to quickly verify whether an oversized pipeline is necessary, to assess the costs of using an oversized design against those of building duplicate pipelines, and to identify the pipeline design that minimises levelised cost of CO2 transport. A sensitivity analysis shows that the correlations are applicable for a wide-range of values for flow rate, transport distance, discount rate, steel price, booster pump and electricity costs. In addition, the correlations for pipeline cost and optimal diameter developed in this paper can be integrated into and accelerate the existing large scale, staged CO2 pipeline network optimisation models.