Professor Dianne Wiley

The main source of CO2 emissions in an integrated steel manufacturing plant comes from the need to use a carbon source, often coal, in the steel making process. Amongst the pathways for reducing CO2 emissions is the application of carbon capture, transport and storage (CCS) technologies. This paper presents a scoping-level economic evaluation of transport and storage location options for CO2 captured from an iron and steel plant located in Port Kembla, NSW, Australia. Pipeline (single and hub) and ship transport of CO2, and two injection locations are considered. Estimated costs are lowest for the hub transport case injecting at the Gippsland basin (~35% lower than for single source cases) and highest for the shipping case. For the single-source cases, transport via pipeline to the Darling basin is slightly more attractive in terms of unit costs. The hub transport cases were between two-thirds and half of the cost of the shipping case. Although the shipping transport option presented the highest cost of the cases considered, there is still a case to be made for ship transport if the project duration is short.

We designed a composite of carbon quantum dots (CQDs) with a carbon layer (CL) covering Cu2O nanocatalysts (CL@CQDs/Cu2O), which exhibited better photocatalytic performance than pure Cu2O and CQDs/Cu2O particles with good stability and efficiency for CO2 conversion.

This paper describes a simplified method to estimate the cost of CO2 avoided for a power plant with a novel CO2 capture system based on only a limited number of fundamental input parameters used to establish basic mass and energy flows for the plant. The cost calculation method follows a sequential approach, estimating first the cost and efficiency penalty impacts of those elements of the plant that are standard and well characterized. We then define the cost gap allowed for the novel elements to break even against a benchmark plant. This method allows one to estimate: (i) the maximum cost reduction potential that a novel CO2 capture technology can achieve with respect to a benchmark technology, and (ii) target breakeven costs for technology developers in the form of combinations of CAPEX and OPEX for a novel capture technology needed to make the technology competitive with the benchmark system. Case studies are presented applying the proposed method to post-combustion and oxy-combustion capture systems, showing that: (i) a clear relationship exists between the breakeven costs and the efficiency penalty caused by the CO2 capture process, mainly because of its effect on the specific capital cost ($/kWe) of the conventional power plant components; and (ii) the minimum cost of CO2 avoided is closely related to the capture system efficiency penalty. For the case study assumptions, avoidance costs vary from ~20 $/tCO2 to ~60 $/tCO2 for efficiency penalties ranging from 2.7% pts to 11% pts, respectively.

Climate change issues have led many countries to actively participate to international conventions, with the aim of reducing the impact of human activities on the environment. In this framework the Paris Agreement has established to keep the temperature rise below 2°C above the pre-industrial level. One suitable mitigation option is to remove carbon dioxide, before it is emitted into the atmosphere. Several technologies are available, including chemical processes where acid gases are absorbed by aqueous alkanolamines solutions. Although this process is already widely used in industry, these solvents are characterized by high energy requirements, in addition to other disadvantages such as corrosion and degradation. Recently, alternative solvents are being studied as possible substitutes for traditional amine solutions. Precipitating solvents are considered in chemical absorption processes because of their characteristic of forming a solid phase, which allows the removal of one reaction product from the liquid solution, therefore shifting the equilibrium of the reaction and so enhancing the mass transfer of the CO2 from the vapor phase to the liquid phase. One class of precipitating solvents are amino acids, with several different types which can be used in aqueous solution. Previous studies have identified the most suitable types for the capture of carbon dioxide and have highlighted the additional advantages of low corrosion and high stability towards degradation, in particular for the amino acid species containing a sulfonic group, such as taurine. This work focuses on the use of potassium taurate aqueous solutions for the removal of carbon dioxide from flue gases from natural gas and coal-fired power plants. The aim is to evaluate changes in the solvent performance arising from changes in the flue gases composition and flowrates. The obtained results confirm the possible application of the potassium taurate aqueous solution for CO2 removal both in coal-fired and in NGCC power plants, with different energy requirements.

Absorption of carbon dioxide from gaseous sources such as flue gases from power plants is accomplished for environmental reasons with the aim to reduce emissions of greenhouse gases. Generally, aqueous solutions of alkanolamines are employed with Monoethanolamine (MEA) considered the benchmark solvent. However, it has drawbacks, primarily its volatility and toxicity, and the need for a lot of energy for regeneration. Recently, new solvents such as amino acid aqueous solutions have started to be considered as alternatives to traditional amines. This paper is focused on the development of a model for the simulation of the absorption and regeneration system using potassium taurate for the capture of carbon dioxide. Detailed modelling of this system is currently limited by the lack of thermodynamic parameters for use in simulations. ASPEN Plus® has been chosen as the framework for developing the model. Species not present by default in the database have been added and appropriate parameters have been determined for obtaining a reliable description of the Vapor¿Liquid¿Solid Equilibrium by means of the Electrolyte-NRTL method.

Chemical absorption is widely regarded as the most commercially ready technology for postcombustion CO2 capture from large industrial emission sources. The benchmark solvent is monoethanolamine (MEA). Alternate solvents to MEA have been developed with improved properties such as solvent loading, regeneration energy, and absorption rate. Improvements in solvent properties can be challenging because of possible adverse interactions between solvent properties. Ideally improving all solvent properties and process designs concurrently is desirable to reduce the total cost of CO2 capture. The changes in cost of CO2 capture for postcombustion CO2 capture from a black-coal power plant using absorption are investigated using Monte Carlo simulations, where key solvent parameters are varied simultaneously. Different classes of solvents are considered covering aqueous and phase-change solvents in conventional and encapsulated solvent systems. The results show that it is not necessary for new solvents to have superior values for all properties. There are combinations of solvent properties where low total capture cost can be achieved because improvements in the more significant parameters offset smaller or negative improvement in other parameters. In particular, low total capture cost can be achieved when solvents have the following properties: good stability toward SOx and NOx, a low heat of reaction, a high absorption rate, a low water vaporization rate, and a low price per unit of the solvent. The results also show that regardless of the solvent type, different solvent systems can potentially achieve almost the same lowest capture cost of approximately U.S. $37-39 per tonne of CO2 avoided.

Carbon Capture and Storage (CCS) has been acknowledged as a technology for CO2 emission reduction. However, developments to lower cost and energy consumption remains an important challenge. Exergetic and exergoeconomic analyses are methods which could be applied to optimize the energy consumption of CO2 capture technologies. An exergetic analysis reveals the locations and causes of inefficiency in an energy conversion process and provides options for improvements. An exergoeconomic analysis establishes the process of cost formation of different streams, including products, within energy systems based on exergy and economic cost balances. This paper aims to develop an exergy-based analysis of a post-combustion CO2 capture process using chemical absorption. A comprehensive flowsheet model has been built for an MEA-solvent chemical absorption, using ASPEN PlusTM Version 8.6 for a coal-fired power plant with a capture rate of 90%. Results have shown the highest irreversibilities to occur in the units related to the chemical capture of CO2 (77% of total losses) and in the CO2 pipeline compressor (9% of total losses). An improvement in the design of the plant reduces the unit cost of carbon capture from 35.0 US$/tonCO2 in the baseline case to of 31.8 US$/tonCO2.

Encapsulated solvents are a solvent system for CO2 capture, where the operating solvent fluid is enclosed in a thin membrane capsule with a diameter of 100-600 µm. The encapsulation provides a significantly higher surface area compared to conventional packings, which potentially reduces the absorber dimensions. In this paper, a high-level assessment of costs for postcombustion CO2 capture using encapsulated solvent systems is carried out to identify key areas for future development. Two process configurations for an encapsulated solvent system are assessed. In the first process configuration, multiple fixed-bed columns are used as the absorber and regenerator. In the second process configuration, a circulating fluidized-bed absorber and a bubbling fluidized-bed regenerator are used. For each system, possible cost reductions through improvements in the capsule properties are investigated. Key design and operational challenges for these systems are also evaluated. The capture costs for using an encapsulated MEA 30% wt. solvent system are found to be 60% to 2 times higher than a conventional MEA solvent system. Higher capture cost is due to the extra membrane resistance in the encapsulated system which increases the regeneration energy required, coupled with higher equipment and capital cost. To reduce cost, future developments for an encapsulated solvent system should consider implementing a suitable heat recovery scheme within the process, using novel absorber and/or regenerator column designs and using solvents encased in very thin capsules. The performance of the encapsulated system could also be improved by using solvents other than MEA with more favorable properties.

This paper performs a techno-economic analysis of natural gas-fired combined cycle (NGCC) power plants integrated with CO2 selective membranes for post-combustion CO2 capture. The configuration assessed is based on a two-membrane system: a CO2 capture membrane that separates the CO2 for final sequestration and a CO2 recycle membrane that selectively recycles CO2 to the gas turbine compressor inlet in order to increase the CO2 concentration in the gas turbine flue gas. Three different membrane technologies with different permeability and selectivity have been investigated. The mass and energy balances are calculated by integrating a power plant model, a membrane model and a CO2 purification unit model. An economic model is then used to estimate the cost of electricity and of CO2 avoided. A sensitivity analysis on the main process parameters and economic assumptions is also performed. It was found that a combination of a high permeability membrane with moderate selectivity as a recycle membrane and a very high selectivity membrane with high permeability used for the capture membrane resulted in the lowest CO2 avoided cost of 75¿US$/tCO2. This plant features a feed pressure of 1.5¿bar and a permeate pressure of 0.2¿bar for the capture membrane. This result suggests that membrane systems can be competitive for CO2 capture from NGCC power plants when compared with MEA absorption. However, to achieve significant advantages with respect to benchmark MEA capture, better membrane permeability and lower costs are needed with respect to the state of the art technology. In addition, due to the selective recycle, the gas turbine operates with a working fluid highly enriched with CO2. This requires redesigning gas turbine components, which may represent a major challenge for commercial deployment.

There has been increasing interest in the development of solvents for CO2 capture including solvents that involve precipitation during CO2 absorption. On the basis of Le Chatelier's principle, the CO2 absorption equilibrium can be shifted by removing one of the reaction products, resulting in a higher absorption capacity. Two phase-change solvents are investigated: promoted potassium carbonate (where the CO2 is incorporated in the solid phase) and potassium taurate (where the CO2 is incorporated in the liquid phase). A high-level assessment is performed with the two phase-change solvents in order to identify key areas in solvent system design for possible cost reduction. The impacts of absorption contactor type, the addition of a solid-liquid separator, and heat integration opportunities on capture cost and total heat duty are investigated. For both phase-change solvents, the lowest capture cost is found when the CO2 absorption is operated in a packed column and advanced heat exchanger integration is used in which the dissolution heat exchanger duty is supplied without consuming low pressure (LP) steam for the power plant. For the cases investigated, there is little difference in capture cost between the two phase-change solvents.

Natural gas combined cycle (NGCC) power plants have emission intensities a half to a third that of current coal-fired power plants. To meet more stringent emission targets, it is essential to reduce the emissions of these plants to an even lower level. Co-firing gasified biomass with natural gas (NG) reduces the plant emissions while allowing continued use of existing assets. If CO2 capture and storage are also applied, negative emissions may result which could provide additional CO2 credits to reduce the overall cost of decarbonising electricity generation. This paper investigates the impact of biomass gas quantity and quality on the performance and economics of a 547 MWe NGCC plant retrofitted with biomass gas co-firing. The analysis considers co-firing with and without CO2 capture. Three co-firing levels (5%, 20%, 40%) and three biomass gasification technologies (atmospheric air-blown gasification, pressurized oxygen-blown gasification and atmospheric indirectly heated gasification) are evaluated. Compared to the baseline NGCC power plant, at low co-firing levels, the type of gasification technology does not significantly affect the overall thermal efficiency, CO2 emission intensity or cost of electricity (COE). However, at higher levels of co-firing, the overall thermal efficiency increases by up to 2.5% LHV for the atmospheric air-blown gasifier but decreases by about 0.4% LHV for the pressurized oxygen-blown gasification and 2.5% for atmospheric indirectly heated gasification technologies. The CO2 emission intensity also changes by up to 0.16-0.18 t/MWh at co-firing levels of 40% for all three gasification technologies, while the COE increases by 0.12-0.18 $/MWh. The analysis also shows that the increase in the fuel flow rate is more significant for BGs with lower heating values. The increase in the fuel flow rate can increase the topping cycle efficiency but requires more modifications to the gas turbine. Thus, co-firing BGs with lower heating value might be less suited to retrofit scenarios. By applying capture to co-firing plants, negative emissions are achieved at medium and high co-firing levels with 7-18% increase in the cost of electricity relative to NGCC with capture. An evaluation of the effect of incentive schemes shows that relatively modest incentives (carbon price > 27 $/t CO2 and REC > 10 $/MWh or combination of both at lower levels) are required to make co-firing cost competitive, while higher incentives are required for co-firing coupled with capture (carbon price > 46 $/t CO2 and REC > 78 $/MWh or combination of both at lower levels). As the co-firing level increases, lower incentives are needed to achieve economic feasibility.

Optimising CO2 transport and injection is a challenging issue in Carbon Capture and Storage (CCS), not only because of the complexity of the problem, but also because of timing effects when introducing new sources and/or sinks into the CO2 transport infrastructure. In particular, the effects of storage capacity, injection site location and reservoir properties can propagate to capture and transport costs, affecting the design of the CO2 pipelines. For example, if an injection site does not have enough capacity to store the total amount of CO2 from a capture project, decision makers would need to consider whether to use a larger capacity site, or use the site with small capacity and later switch to a larger capacity site or use both sites.This paper considers the effects of storage capacity, injectivity and distance to source of two sinks on optimal CO2 transport infrastructure design and a static supply of CO2. Optimal pipeline configurations and sink selection were determined under different combinations of CO2 flow rate, pipeline length and storage site properties. In one scenario, two sinks both have infinite capacity but different injectivities and distances to the emission source. In the other scenario, one sink is relatively small but has a better injectivity or proximity to the emission source.A decision tree approach was developed to provide a quick method for high-level sink selection and pipeline routing for the two scenarios based on the key project parameters including sink capacity, injectivities, pipeline distances and well cost. The scenarios where the decision trees may be useful for simplifying the design of large-scale CO2 pipeline networks have also been analysed.

The main source of CO2 emissions in an integrated steel manufacturing plant comes from the need to use a carbon source, often coal, in the steel making process. Among the pathways for reducing CO2 emissions is the application of carbon capture, transport and storage (CCS) technologies. This study undertakes a scoping-level evaluation of the economic viability of transport and storage location options for CO2 captured from an iron and steel plant located in Port Kembla, NSW, situated on the eastern coast of Australia. Both pipeline and ship transport of CO2 are considered, as well as two injection locations: the Darling Basin in NSW and the Gippsland Basin in the state of Victoria, Australia. The cost of CO2 transport and storage are estimated for four specific transport and storage options in south-east Australia, including the cost of pipelines/shipping, boosters, wells, other facilities, monitoring, energy and on-costs. The cases consider either a single CO2 source (emissions from Port Kembla) to a single pipeline or shipping port, or the contribution by the CO2 source from Port Kembla to a collection of CO2 sources including other CO2 sources in NSW, into a pipeline network. The sensitivity of the results to several economic and design parameters, such as flow rate, and project lifetime, is also assessed. Scoping level cost estimates for transport and storage of the CO2 are lowest for the hub transport case injecting at the Gippsland basin and highest for the case involving shipping with injection in the Gippsland basin. For the single-source cases, transport via pipeline to the Darling basin is a slightly more attractive option in terms of unit costs. Although pipeline transport to both the Darling and Gippsland basins are very close in terms of transport and storage costs (less than 0.2% difference), the cost of transporting to the Darling basin is less sensitive to variations of the cost parameters explored in this study. The lowest transport and storage costs found in this study were for the pipeline hub transport cases, more than 35% lower on average than for the single source cases. Regardless of the sensitivity scenario, the hub transport cases were between two-thirds and half of the cost of the shipping case. This highlights the importance of economies of scale in CO2 transport, achieved by employing larger diameter pipelines. This leads to decreases in both the unit capital costs by allowing larger capacities of transport, as well as in operating expenses by decreasing pressure losses along the pipelines, thus requiring less energy for compression. Although the shipping transport option presented the highest cost of the cases considered, there is still a case to be made for ship transport if the project duration is short. As ship transport is less CAPEX intensive (35% of total cost), this mode of transport becomes competitive with pipeline transport if the project duration is decreased, or if the discount rate is increased. Further, shipping also becomes more competitive for longer transport distances. For example, if the hub transport options would take several years to implement, a case could be made for utilising ship transport for a few years while the hub pipeline is constructed, and then transporting via the hub once it is available.

This paper presents a novel approach for assessing the economic performance of novel CO2 capture technologies for power plants. The method consists in three main steps: (i) definition of the carbon and energy balances with a simplified approach using few fundamental data on the novel capture technique, (ii) calculation of the CAPEX and OPEX of the conventional unit operations of the power plant integrating the novel technology and (iii) calculation of the minimum theoretical cost of CO2 avoided (CCA) and of the breakeven CAPEX and OPEX of the novel capture technology making it competitive with the benchmark capture technology. The proposed methodology has been applied to selected technologies showing that: (i) a clear relationship exists between the breakeven cost and the efficiency penalty which mainly affects the specific cost (in $/kWe) of the conventional components of the power plant; (ii) ideal minimum CCA is closely related to the efficiency penalty and range between ~20 $/tCO2 for efficiency penalties of 2.7% pts. and ~60 $/tCO2 for efficiency penalties of 11% pts. Significant reductions in the ideal minimum CCA may only be obtained through technologies allowing consistent economic savings by the removal of major components of the conventional power plant.

High-pressure CO2 pipeline transport is an important component in the Carbon Capture and Storage (CCS) system. With changes in market demand caused particularly by the growing utilization of renewable energy, variations in and intermittency of CO2 supply from capture plants at large scale fossil fuel power plants are inevitable. During power plant load variations, the fluctuations in the CO2 flow rate may subsequently cause pressure and temperature instabilities, and two-phase flow may occur when the pressure and temperature drop. This will require significant improvement in the operational flexibility during CO2 transport in order to maintain proper control of the CO2 flowing in the pipeline. Load variation is a complex problem because the transition between one- and two-phase flow is a dynamic process, and the effect of flow rate, pressure and temperature fluctuations on the phase transition is not clear. Based on these considerations, this paper presents results from a small-scale experiment and large-scale simulations on dynamic phase changes in pipelines during flexible CO2 transport under high-pressure. The results show potential phase change can occur inside the pipe and put potential threat to pipeline operation, thus the simulation can be a promising tool to optimize the operating conditions and make the pipeline system more flexible.