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In this work, a novel hydrogen production process (Integrated Chemical Looping Water Splitting "ICLWS") has been developed. The modelled process has been optimised via heat integration between the main process units. The effects of the key process variables (i.e. the oxygen carrier-to-fuel ratio, steam flow rate and discharged gas temperature) on the behaviour of the reducer and oxidiser reactors were investigated. The thermal and exergy efficiencies of the process were studied and compared against a conventional steam-methane reforming (SMR) process. Finally, the economic feasibility of the process was evaluated based on the corresponding CAPEX, OPEX and first-year plant cost per kg of the hydrogen produced. The thermal efficiency of the ICLWS process was improved by 31.1% compared to the baseline (Chemical Looping Water Splitting without heat integration) process. The hydrogen efficiency and the effective efficiencies were also higher by 11.7% and 11.9%, respectively compared to the SMR process. The sensitivity analysis showed that the oxygen carrier–to-methane and -steam ratios enhanced the discharged gas and solid conversions from both the reducer and oxidiser. Unlike for the oxidiser, the temperature of the discharged gas and solids from the reducer had an impact on the gas and solid conversion. The economic evaluation of the process indicated hydrogen production costs of $1.41 and $1.62 per kilogram of hydrogen produced for Fe-based oxygen carriers supported by ZrO 2 and MgAl 2 O 4 , respectively - 14% and 1.2% lower for the SMR process H 2 production costs respectively. • The process H 2 efficiency is improved by 11.7% compared to steam methane reforming. • The process effective efficiency is 11.9% higher than to steam methane reforming. • The process has carbon intensity of 0.84 kg CO 2 per Nm3 of H 2 produced. • Oxygen carrier to fuel/steam ratio affects the process reactors conversions. • The H 2 production cost of the process is 14% lower than steam methane reforming. [ABSTRACT FROM AUTHOR]

This paper presents a novel methodology for the optimisation of the preliminary design of heat-integrated multicomponent distillation sequences. This is achieved through use of a reduced process superstructure where the role of splitting each adjacent key component pair is assigned to an individual separation column, greatly reducing the size and complexity of the problem. This methodology uses information about other process streams on site with which heat can be exchanged within the initial design in order to find a plant-wide optimal separation configuration with the aim of reducing the cost of heating provided by utilities including those used for heating and cooling process streams. In order that this model can be formulated as a mixed-integer linear program, this model utilises a discretised temperature grid where stream temperatures are allowed to vary. This methodology was tested on an example of a mixed alkane feed stream, with the sequence changing dependent on the degree of process integration. The method was found to have the potential for significant cost reductions compared to a heuristic design, with the example exhibiting a cost saving of over 50% and a reduction in CO 2 associated with process heating of almost 60%, though the magnitude of these savings is highly dependent on the specific example to which it is applied. [ABSTRACT FROM AUTHOR]

Through more than two decades' intensive research, ionic liquids (ILs) have exhibited significant potential in various areas of research at laboratory scales. This suggests that ILs-based industrial process development will attract increasing attention in the future. However, there is one core issue that stands in the way of commercialisation: the high cost of most laboratory-synthesized ILs will limit application to smallscale, specialized processes. In this work, we evaluate the economic feasibility of two ILs synthesized via acid-base neutralization using two scenarios for each: conventional and intensification processing. Based upon our initial models, we determined the cost price of each IL and compared the energy requirements of each process option. The cost prices of triethylammonium hydrogen sulfate and 1-methylimidazolium hydrogen sulfate are estimated as $1.24 kg-1 and $2.96-5.88 kg-1, respectively. This compares favourably with organic solvents such as acetone or ethyl acetate, which sell for $1.30-$1.40 kg-1. Moreover, the raw materials contribute the overwhelming majority of this cost and the intensified process using a compact plate reactor is more economical due to lower energy requirements. These results indicate that ionic liquids are not necessarily expensive, and therefore large-scale IL-based processes can become a commercial reality. [ABSTRACT FROM AUTHOR]

The UK electricity grid is expected to supply a growing electricity demand and also to cope with electricity generation variability as the country pursues a low-carbon future. Molten Salt Reactors (MSRs) could offer a solution to meet this demand thanks to their estimated low capital costs, low operational risk, and promise of reliably dispatchable low-carbon electricity. In the published literature, there is little emphasis placed on estimating or modelling the future impact of MSRs on electricity grids. Previous modelling efforts were limited to quantifying the value of renewable energy sources, energy storage and carbon capture technologies. To date, no study has assessed or modelled MSRs as a competing power generation source for meeting decarbonization targets. Given this gap, the main objective of this paper is to explore the cost benefits for policy makers, consumers, and investors when MSRs are deployed between 2020 and 2050 for electricity generation in the UK. This paper presents results from electricity systems optimization (ESO) modelling of the costs associated with the deployment of 1350 MW e MSRs, from 2025 onwards to 2050, and compares this against a UK grid with no MSR deployment. Results illustrate a minimum economic benefit of £1.25 billion for every reactor installed over this time period. Additionally, an investment benefit occurs for a fleet of these reactors which have a combined net present value (NPV) of £22 billion in 2050 with a payback period of 23 years if electricity is sold competitively to consumers at a price of £60/MWh. [ABSTRACT FROM AUTHOR]

A new approach is required to determine a technology's value to the power systems of the 21st century. Conventional cost-based metrics are incapable of accounting for the indirect system costs associated with intermittent electricity generation, in addition to environmental and security constraints. In this work, we formalise a new concept for power generation and storage technology valuation which explicitly accounts for system conditions, integration challenges, and the level of technology penetration. The centrepiece of the system value (SV) concept is a whole electricity systems model on a national scale, which simultaneously determines the ideal power system design and unit-wise operational strategy. It brings typical Process Systems Engineering thinking into the analysis of power systems. The model formulation is a mixed-integer linear optimisation and can be understood as hybrid between a generation expansion and a unit commitment model. We present an analysis of the future UK electricity system and investigate the SV of carbon capture and storage equipped power plants (CCS), onshore wind power plants, and grid-level energy storage capacity. We show how the availability of different low-carbon technologies impact the optimal capacity mix and generation patterns. We find that the SV in the year 2035 of grid-level energy storage is an order of magnitude greater than that of CCS and wind power plants. However, CCS and wind capacity provide a more consistent value to the system as their level of deployment increases. Ultimately, the incremental system value of a power technology is a function of the prevalent system design and constraints. [ABSTRACT FROM AUTHOR]

Whilst CO 2 capture and storage (CCS) technology is widely regarded as being an important tool in mitigating anthropogenic climate change, care must be taken that its extensive deployment does not substantially increase the water requirements of electricity generation. In this work, we present an evaluation of the cooling demand of an amine-based post-combustion CO 2 capture process integrated with a coal-fired power plant. It is found that the addition of a capture unit translates into an increase in the total cooling duty of ≈47% (subcritical), ≈33% (supercritical) and ≈31% (ultra-supercritical) compared to a power plant without capture. However, as the temperature at which this cooling is required varies appreciably throughout the integrated power capture process, it is found that his increase in cooling duty (MW) does not necessarily lead to an increase in cooling water usage (kg H 2 O /MW). Via a heat integration approach, we demonstrate how astute cascading of cooling water can enable a reduction of cooling water requirements of a decarbonised power plant relative to an unmitigated facility. This is in contrast to previous suggestions that the addition of CCS would double the water footprint. [ABSTRACT FROM AUTHOR]

Biomass-based power generation combined with CO 2 capture and storage (Biopower CCS) currently represents one of the few practical and economic means of removing large quantities of CO 2 from the atmosphere, and the only approach that involves the generation of electricity at the same time. We present the results of the Techno-Economic Study of Biomass to Power with CO 2 capture (TESBiC) project, that entailed desk-based review and analysis, process engineering, optimisation as well as primary data collection from some of the leading pilot demonstration plants. From the perspective of being able to deploy Biopower CCS by 2050, twenty-eight Biopower CCS technology combinations involving combustion or gasification of biomass (either dedicated or co-fired with coal) together with pre-, oxy- or post-combustion CO 2 capture were identified and assessed. In addition to the capital and operating costs, techno-economic characteristics such as electrical efficiencies (LHV% basis), Levelised Cost of Electricity (LCOE), costs of CO 2 captured and CO 2 avoided were modelled over time assuming technology improvements from today to 2050. Many of the Biopower CCS technologies gave relatively similar techno-economic results when analysed at the same scale, with the plant scale (MW e ) observed to be the principal driver of CAPEX (£/MW e ) and the cofiring % (i.e. the weighted feedstock cost) a key driver of LCOE. The data collected during the TESBiC project also highlighted the lack of financial incentives for generation of electricity with negative CO 2 emissions. [ABSTRACT FROM AUTHOR]

• Detailed sustainability assessment of carbon utilisation processes is crucial. • Potential use of wind energy in transport and power sectors was analysed. • Six countries that vary in grid mixes and gasoline consumption were assessed. • At present, direct use of wind energy to decarbonise the power sector is advisable. Methanol from captured CO 2 provides a more sustainable alternative to gasoline due to its low carbon footprint, yet it requires a large amount of renewable energy that could be used instead to decarbonise the electricity mix. A techno-economic and environmental analysis of methanol produced from captured CO 2 and renewable energy is conducted to shed light on the transportation-power nexus. The investigated scenarios differ in how the carbon-free energy source – electricity from wind – is used to either decarbonise the electricity mix or produce green methanol to displace conventional fossil fuels. The assessment is carried out for six countries that differ in the composition of their electricity mix and gasoline consumption. The results of this holistic assessment show that, at present, decarbonising the electricity grid using renewable energy sources and carbon capture and storage would offer greater environmental benefits, without incurring large changes in direct economic costs, compared to producing methanol from the hydrogenation of captured CO 2. Though this insight might change in the future if the carbon intensity of the mix is reduced and green methanol becomes cheaper, it highlights the need to consider the transportation-power nexus in assessing alternative fuels and thereby prevent shifting of emissions from one sector to another over their life cycle. [ABSTRACT FROM AUTHOR]