• Energy Research

AbstractIn this paper, Australia is used as a case study to evaluate potential pathways for staged deployment of low-emission technologies in an integrated, emission intensive electricity market. We assume that carbon capture and storage is implemented at existing and new power plants. To meet projected demand increase by 2050, the total generation capac ty increases by 35%. The cost of electricity in 2050 is more than double the current value, with a moderate annual increase between now and then. An 80% emission reduction target can be achieved by 2050. The results are compared with the future generation scenarios previously analysed by CSIRO and AEMO.

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.

Abstract Recently it has been postulated that a post combustion capture process with three membrane stages and cryogenic separation can achieve high CO 2 recovery and purity while being economically competitive with existing commercial carbon capture technology ( Merkel et al., 2010 ). The advantage of this design is the use of burner feed air as a membrane sweep gas to ensure high CO 2 recovery. However, this results in dilution of oxygen in the burner and reduces the overall efficiency of the power station. In this study, two modifications to this process are considered. First, to ensure that the feed burner air supply is not oxygen deficient, we consider the addition of a small air separation membrane unit on this feed air supply. The O 2 enrichment design allows much greater CO 2 concentrations to be accommodated within this burner air supply. The resulting capture cost of the optimised process is reduced to less than US$ 32 per tonne avoided, with a burner air supply containing 33 mol% CO 2 . If flue gas desulphurisation and selective catalytic reduction are required then the cost of capture is less than US$ 43 per tonne avoided. However, one of the consequences of the oxygen enrichment is the need for four membrane stages which may limit its practical application. In comparison, a simplified process that removes the final CO 2 membrane concentration while still achieving high CO 2 recovery has increased energy demand and operating costs but results in lower overall capital cost. The cost of capture of this simplified process remains comparable at less than US$ 35 per tonne avoided for a sweep gas containing 9 mol% CO 2 .

Bio-Energy with Carbon Capture and Storage (BECCS) is an emerging energy conversion technology with the potential to deliver ‘negative emissions’, a net removal of CO2 from the atmosphere that may be necessary to achieve the net-zero targets adopted in the Glasgow Climate Pact at COP26. This paper uses Life Cycle Assessment (LCA) to investigate the environmental impacts of co-firing dry waste biomass (wood and paper waste) while implementing CCS technology (i.e., BECCS) in a conventional black coal-fired power plant. The LCA covers CO2 emissions and trace contaminants, determined via combustion modelling coupled with chemical-equilibrium-based ash-forming element and trace element calculations. As a case study, the context of New South Wales, Australia, is analysed to assesses the viability and discuss policy implications of waste co-firing BECCS as a future energy source for coal-reliant regions. An increase in co-firing ratio is found to decrease emission intensity. At current typical efficiencies, BECCS with a 10 % co-firing ratio can reduce emission intensity from 938 to 181 kgCO2/MWh. At 20 % to 25 % co-firing, the emission intensity of BECCS is comparable with other renewable technologies, and negative emissions are achievable above 30 %, although waste availability in NSW is insufficient to achieve these levels. Moreover, BECCS increases environmental impact in all categories except for global warming potential (GWP), land use, and terrestrial acidification. Nonetheless, when aggregating all impacts, the large reduction in GWP drives an endpoint score reduction, indicating that co-fired BECCS may be preferred over sub-critical black (bituminous) coal-fired power without or with CCS, or other higher emission intensity coal-fired power generation. Therefore, policy makers should consider incentivising waste co-firing BECCS as part of future energy policies towards achieving the net-zero targets, weighing its benefits against other environmental impacts, waste availability and competition with recycling ...

AbstractAn economic model for ship transport of CO2 is developed and benchmarked against published studies. The costs and benefits of ship transport for several likely CCS scenarios are compared against pipeline transport of CO2 for offshore injection. The results show that ship transport can be cost competitive with pipelines. The largest shipping cost components are electricity and fuel, each accounting for almost 30% of the total cost. Capital costs only contribute around 28% of the total shipping cost, compared to more than 70% for pipeline transport. Economies of scale can make shipping more cost-effective over long distances.

Abstract This paper performs a techno-economic analysis of natural gas-fired combined cycle (NGCC) power plants integrated with CO 2 selective membranes for post-combustion CO 2 capture. The configuration assessed is based on a two-membrane system: a CO 2 capture membrane that separates the CO 2 for final sequestration and a CO 2 recycle membrane that selectively recycles CO 2 to the gas turbine compressor inlet in order to increase the CO 2 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 CO 2 purification unit model. An economic model is then used to estimate the cost of electricity and of CO 2 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 CO 2 avoided cost of 75 US$/t CO2 . 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 CO 2 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 CO 2 . This requires redesigning gas turbine components, which may represent a major challenge for commercial deployment.

AbstractWide deployment of carbon capture and storage (CCS) will require extensive transportation infrastructure, quite often in the form of pipelines. The rollout of such large-scale infrastructure would undoubtedly require very large investments. In regions with several CO2 emission sources, it is possible that not all of the major CO2 sources will implement CCS at the same time. Shared oversized pipeline designs are often proposed in order to form a “cluster” of CO2 sources and serve as the backbone for an expanding CO2 transportation infrastructure, to which emission sources will be connected. This paper analyses the economics of using oversized and parallel pipelines for different typical pipeline length and CO2 flow rate combinations. For new CCS projects, the expansion methodology presented in this paper can identify the optimal pipeline design that minimises the cost per tonne of CO2 avoided over the life of the project. For existing projects, the expansion methodology identifies the optimal pipeline design change, which may include either using an existing pipeline as CO2 supply increases or duplicating pipelines.

AbstractThis paper shows the effects of storage capacity on the selection of least cost CO2 transport infrastructure design where there are two candidate injection sites (sinks) and a static supply of CO2 (source). We investigate the least cost pipeline configuration under different combinations of CO2 flow rates, pipeline lengths and storage capacities. A frequency distribution of least cost design shows that the capacity of the smaller sink is one of the main drivers for pipeline design. The insights gained from this study can also be applied in large-scale CO2 pipeline networks optimisation.