Due to the long duration of Carbon Capture and Storage projects and the uncertainty of the captured CO_2 amounts, making decisions about the construction of transport infrastructure in the early stages is challenging. The objective of this study is to propose a stochastic programming model to optimize the deployment of infrastructure, specifically pipelines and ships, to transport CO_2 from industrial sources to sequestration sites. The proposed model accounts for uncertainties in the capture (or supply) of CO_2 and is tested using an illustrative case study of the Humber cluster in the UK. The constructed scenario trees incorporate the risk of potential closure and reactivation of the capture facilities, allowing decision makers to make more robust first stage decisions about the type and capacity of transport infrastructure to construct. The experiments in this paper examine changes in optimal investment decision for a range of uncertainties. For example, the trade-off between investment in pipelines and ships is influenced by assumptions about the potential for ships to relocate to other regions if CCS projects close and key policy decisions (e.g. availability of upfront funding for infrastructure investment). For our illustrative case study, pipelines are preferred in cases with lower probabilities of closure in later periods when sufficient budget is available. When a higher probability of project closure is considered or discount rate is increased to typical commercial rates, our model indicates that investment in ships will dominate.

Waste-to-Energy (WtE) is becoming an important application sector for carbon capture utilization and storage (CCS) due to its role in urban waste management and its inherent potential of achieving negative emissions. This study is built upon a series of modelling activities, with three representative WtE plant steam cycle configurations selected to integrate monoethanolamine (MEA) based Post-combustion CO2 Capture (PCC). With 60% biogenic carbon in the fuel, a set of key performance indicators of the investigated WtE plant configurations are presented. Results show that there is significant potential for heat recovery from the PCC process to provide heat for District Heating (DH). With advanced heat recovery, the energy utility factor (EUF) of WtE plant could be higher than that for WtE plant without PCC. Results also show that optimised process design can be used to enable ultra-high CO2 capture (99.72% in this study) to be achieved with only a marginal increase in specific reboiler duty when compared with 95% capture. This study also highlights the importance of differentiating carbon intensities for different product bases: electrical or thermal or waste, which are important when comparing WtE CCS with other carbon saving technologies. The findings of this study provide valuable information for the future implementation of carbon dioxide capture technology in the WtE sector.

Waste-to-Energy (WtE) has become an attractive application for carbon capture utilization and storage (CCS) due to its role in decarbonizing urban waste management and its inherent potential of achieving negative emissions. Building upon a series of modeling activities, the application of interim solvent storage (ISS) is researched with the objective of improving the heat supply ability of WtE combined heat and power (CHP) plants integrated with Post-combustion CO2 capture (PCC). This paper uses a mathematical programming-based methodology using a design-day approach to investigate the optimal operation of a WtE-CHP plant with the implementation of interim solvent storage. The results show that the usage of a load-following gas boiler is reduced as a result of implementing solvent storage thereby also lowering fossil CO2 emissions. The amount of wasted excess heat is also reduced. However, the plant with interim solvent storage has a lower annual profit as the increased capital costs of building storage tanks are higher than the savings from lower boiler heat usage and lower CO2 taxes with these results highly sensitive to the problem setting and input parameters. We observe that solvent storage is not operational during the summer design day suggesting that seasonal solvent or thermal storage may be a more useful alternative

The deployment of Carbon Capture and Storage technologies in the waste management sector can make municipal and industrial waste a strategic resource for climate change mitigation. The generation of energy, in the form of electricity and heat, via the processing and incineration of waste already avoids methane emissions from landfill. The addition of CCS to Waste-to-Energy plants with CO2 capture levels close to 99% can reduce their CO2 emissions to the atmosphere close to zero. With CCS, biogenic carbon in waste becomes a domestic source of negative emissions with a supply chain that would complement other negative emission technologies, such as Bio-Energy with CCS (BECCS). The NEWEST-CCUS project is an ongoing €2.5M multidisciplinary (2019-2022) project involving academics and researchers from six organisations and four European countries. It seeks to improve understanding of technologies and opportunities for negative emissions in the waste-to-energy sector. This paper outlines the broad range of activities undertaken by the consortium in response to key challenges facing the sector.

In future energy supply systems, hydrogen and electricity may be generated in decarbonized industrial clusters using a common infrastructure for natural gas supply, electricity grid and transport and geological storage of CO2. The novel contribution of this article consists of using sequential combustion in a steam methane reforming (SMR) hydrogen plant to allow for capital and operating cost reduction by using a single post-combustion carbon capture system for both the hydrogen process and the combined cycle gas turbine (CCGT) power plant, plus appropriate integration for this new equipment combination. The concept would be widely applied to any post-combustion CO2 capture process. A newly developed, rigorous, gPROMs model of two hydrogen production technologies, covering a wide range of hydrogen production capacities, thermodynamically integrated with commercially available gas turbine engines quantifies the step change in thermal efficiency and hydrogen production efficiency. It includes a generic post-combustion capture technology – a conventional 30%wt MEA process - to quantify the reduction in size of CO2 absorber columns, the most capital intensive part of solvent-based capture systems. For a conventional SMR located downstream of an H-class gas turbine engine, followed by a three-pressure level HRSG and a capture plant with two absorbers, the integrated system produces ca. 696,400 Nm3/h of H2 with a net power output of 651 MWe at a net thermal efficiency of 38.9%LHV. This corresponds to 34 MWe of additional power, increasing efficiency by 4.9% points, and makes one absorber redundant compared to the equivalent non-integrated system producing the same volume of H2. For a dedicated gas heated reformer (GHR) located downstream of an aeroderivative gas turbine engine, followed by a two-pressure level HRSG and a capture plant with one absorber, the integrated system produces ca. 80,750 Nm3/h of H2 with a net power output of 73 MWe and a net thermal efficiency of 54.7%LHV. This corresponds to 13 MWe of additional power output, increasing efficiency by 13.5% points and also makes one absorber redundant. The article also presents new insights for the design and operation of reformers integrated with gas turbines and with CO2 capture.

This paper assesses how operational flexibility and the curtailment of renewable energy are connected using a unit commitment and economic dispatch model that includes operational characteristics of conventional power plants and system constraints. A Great Britain test system is analysed under different scenarios of wind (onshore and offshore) and solar installed capacity, showing that an increase in curtailment is mostly expected as wind deployment increases. This curtailment reaches 17% of the annual available variable renewable electricity generation at high wind and solar installed capacities and is mainly driven by the inertial requirement. The best approach to reducing curtailment is, therefore, to reduce the inertia floor by relaxing Rate of Change of Frequency limits. For the assumed curtailment costs, onshore wind presents a stronger correlation with overall curtailment than offshore wind and solar, albeit influenced by the levels of solar installed capacity. Significant reductions in curtailment can be achieved if wind contributes to system balancing requirements. This emphasizes the importance of ensuring that variable renewables are technically able to contribute to system balancing, wherever feasible, and of improving access to revenue streams that incentivise flexible operation of variable renewable generation.

Rapid urbanization, global warming and enhanced quality of life have significantly increased the demand of indoor thermal comfort and air conditioning systems are not a luxury anymore, but a necessity. In order to fulfil this need, it is imperative to develop affordable and environmentally friendly cooling solutions for buildings. In this work, the 3E performance (energetic, economic and environmental) of electrically driven water-cooled vapour compression systems and thermally (solar) driven vapour absorption cooling systems are evaluated and the parameters affecting the performance of solar-driven vapour absorption systems are investigated. The energy simulation software TRNSYS is used to simulate the performance of both systems in order to fulfil the cooling needs of an industrial manufacturing building for the typical climate conditions for Lahore, Pakistan. Primary energy saving, initial investment, operational cost, and carbon footprint indices are used to analyse the performance of both systems. In addition, a parametric code is written in Python and linked with TRNSYS to perform a parametric study to investigate the effects of various parameters such as solar field size, storage tank volume, optimum annual and monthly collector angles, and flow rate in the solar field on the solar-driven vapour absorption chiller performance. The results reveal that around 5% more energy can be absorbed per collector surface area by changing the solar tilt angle on a monthly basis compared to one fixed angle. The analysis shows that electrically driven vapour compression-based cooling systems have much higher running cost and are potentially hazardous for the environment but have lower capital costs. On the other hand, solar thermal systems have lower running costs and emissions but require further reductions in the capital costs or government subsidies to make them viable.

Combustion of individual particles of different woody and agricultural residue biomass have been studied under a laboratory scale rapid-heating apparatus. Particles used were in the size range of 300-1400 mm and weight 0.5-7 mg. A wire mesh element is used to radiatively heat the particle to 1200-1400 K. The apparatus allows a high-speed camera to record the combustion of the individual particles directly. Examination of the resulting video images showed a sequential combustion of volatile matter followed by burn-out of the remaining char for all fuels. Analysis identified differences and patterns in burnout time, combustion behavior and the evolution of char size and shape transformations. Heterogeneous behavior was observed between the different biomass samples and also among particles within some of the samples. Particles with initial prolate (fibrous) shapes have been observed to become more equant (quasi-spherical) during combustion. Measurement of the particle dimensions during its combustion extracted from the images of the high speed recording have allowed evaluation of the size and shape changes to be mapped. Particle size and shape appears to change only slightly during devolatilization and swelling was rarely observed. Following devolatilization, during the remaining char combustion, more pronounced changes in the size and shape of the particle are apparent. In most cases the shrinking char becomes more rounded as the char particle partially melts and contracts due to surface tension. This transformation is more distinct in some of the biomass samples. Profiles and images of the different fuels examined are presented.

Along with renewables and nuclear power, carbon capture and storage (CCS) is expected to play a vital role in decarbonising electricity production. In future electricity systems, CCS power plants will be required to respond to the fluctuating supply of renewable energy by varying their output and through rapid shut-downs and start-ups [1]. This concept of flexible operation initially proposed by academics at the University of Edinburgh [1, 2] allows CCS plants to time-delay the financial and energy output penalty of carbon capture processes. Whilst the concept was developed for conventional fossil fuel power cycles with post-combustion capture, this project is the first to apply it to the Allam Cycle, a recent breakthrough in low-carbon energy generation. The Allam Cycle is an oxy-fired supercritical CO2 power cycle, currently undergoing pilot scale testing as part of a $140m scheme led by NET Power [3]. It is designed to produce zero carbon electricity at competitive efficiency and costs compared to unabated fossil fuel plants, thus exhibiting a step-change in performance compared to state of the art CCS power generation. In the Allam Cycle, shown in Figure 1, an Air Separation Unit produces oxygen which is combusted with natural gas, producing a high-pressure working fluid above 90% supercritical CO2 in volume, which is then used to drive an electricity generating turbine. Most of this CO2 is then compressed and fed back into the cycle, while surplus is removed at the required pressure and quality for pipeline transport. Thus, the cycle inherently captures all CO2 produced, without the expense of an add-on capture system. The potential for enhanced operational flexibility in the Allam Cycle arises from the opportunity to decouple the highly energy intensive step of oxygen production from power generation. The limiting Figure 1 Simplified Allam Cycle Schematic [4]

Highly flexible, low-carbon electricity generation with gas-fired power stations with CO2 capture addresses the challenges of balancing variable renewable electricity supply in low carbon electricity systems. This detailed technical assessment of flexible CO2 capture plant operation at natural gas combined cycle power stations with post-combustion CO2 capture examines the operating strategies of capture plant by-pass and interim solvent storage. We show that solvent storage allows expanding the operating envelope of gas fired CCS power stations by +/- 10%. Further we demonstrate that electricity and CO2 output can be decoupled for up to 3 h with approx. 6000 m(3) of additional solvent inventory for the purpose of reducing the CO2 flow variability in downstream transportation and storage systems, mitigating potentially deleterious injection well effects. 1 h of solvent storage operation at full load can be regenerated in as fast as 2.1 h during continuous operation of the CCS power plant by choosing a controlled steam extraction strategy from the combined cycle and thus throttling the low pressure turbine. The electricity output penalty associated with the delayed regeneration of solvent ranges from 420-450 kWh/tCO(2) with this strategy, which compares to 380 kWh/tCO(2) for immediate regeneration at full load design conditions. By deploying a novel variable speed drive integrally geared compressor model, we find that, unlike previously thought, an uncontrolled steam extraction strategy, referred as a floating steam extraction strategy, can lead to choking of the CO2 compressor during additional solvent regeneration. A pre-compression stage would be necessary under this extraction strategy to restore feasible operation of the main CO2 compressor, and makes this strategy more complex to implement. When decreasing the desorber pressure at part-load care must, therefore, be taken to respect the operating limits of the compressor. To assist with the use of rigorous plant performance data in wider electricity system models, correlations for key performance parameters of NGCC-CCS power plants at varying load, with capture by-pass and additional solvent regeneration are provided.

Nitrogen oxides (NOx) are atmospheric pollutants specifically targeted by legislation which imposes limits on emissions from large scale plant. During combustion, part of the Nitrogen fuel will be released as a component of the volatile matter compounds and as volatile nitrogen, while part will remain in the char. Thus, the fate of volatile-N and char-N becomes crucial for the formation of NOx and, consequently, for determining the concentrations of NO in solid fuels combustion systems. In pulverized fuel combustion, major routes for conversion of the volatile-N are either NO or N-2, while char-N reacts through a set of heterogeneous reactions as the char is oxidized. Measuring high temperature char nitrogen content of the fuels directly reduces the likely uncertainty in NOx emissions from solid fuels on modern power stations using deep furnace air staging High temperature volatile-N and char-N partitioning is investigated by pyrolyzing fuels in a high temperature (1600 degrees C) wire mesh apparatus (HTWM) and analyzing the resulting char. White wood biomass, olive waste, torrefied wood, two bituminous coals and one anthracite coal were used on this study. The volatile yield at high temperatures has been obtained for each sample. The fate of nitrogen released during the pyrolysis as volatile matter and the nitrogen retained in the char has been evaluated for different biomass samples. The nitrogen in the char was measured using a total nitrogen analyzer. Results show a large change in on the volatile yield compared with proximate analysis values for both coals. Only moderate change was observed on the volatile yield for both of the woody biomass that already have high values on proximate analysis, and just a slight increase was obtained on the volatile yield for the olive waste. Differences were found on the fate of nitrogen retained in the char that would lead to NOx formation. The biomass samples release most of their fuel-nitrogen as volatile (between 80 and 95%) while on the coals the volatile nitrogen is wide more variable depending on the coal sample.

The Centre for Energy Policy held a Roundtable on the potential value to the political economy of carbon capture, utilisation and storage (CCUS), in the margins of the Global CCUS Summit held in Edinburgh. This note summarises discussions and reflects on next steps. Participants are listed in the appendix. This note does not attribute comments or views to particular participants. Professor Graeme Sweeney chaired the Roundtable, with Professor Karen Turner, Director of the Centre for Energy Policy, kick-starting the discussion with a presentation on recent research on the potential value of CCUS to the political economy.

The code for the Unit Commitment & Economic Dispatch model that was used in this work is available at: https://gist.github.com/vitali87/20688c161d7b5ad598b5d52b524f4585 Sample output data can be found in the "Example Outputs.zip" file. This corresponds to the case outlined in the article that simulates a system with 5 Allam Cycle plants without Liquid Oxygen Storage, for the winter test week. To run the UCED model: Download "UC AIMMS Allam Cycle Model" code from the github and save as an AIMMS project file. Save the file in a folder that contains all the necessary input datasets, found in the "Universal Inputs for UCED Model.zip" file, and the example outputs, found in the "Example Outputs.zip" file, which are to be overwritten. Do not change the name of the input or output files. Open the project and execute the following procedures: "Main Initialisation" - to initialise the problem "Read from Excell" - to read data from the input files "Main Execution" - to begin running the problem Once the run is complete, execute "Run External Procedure" to overwrite the output files with the new data. To change the test week: Open "Demand Profiles" in 'sets' and change the set definition. Enter "C1" for the winter week and "C21" for the summer week. Another week can alternatively be selected. For example, entering "C45" would allow the model to run with the weather and demand data from the 45th week in the year 2010. Save and close the set. To change the number of plants in the system: Open "PCCSGenerators" in 'sets' and change the set definition. To run with 5 Post Combustion Capture plants, end the list of generators after plant number 5 by commenting the remaining plants. This is done by using "!" after the 5th plant name in the string. Then save and close the set. Repeat the above step for the "ACGenerators" and "AirSeparationUnits" sets, to change the number of Allam Cycle plants in the system. To add or remove oxygen storage capability from the Allam Cycle plants: Open the "Main Initialisation" procedure. To run the model without oxygen storage: make sure the following command is stated: "AC_ASU_coupled := 0;" save and close the procedure To run the model with oxygen storage: make sure the following is command is stated: "AC_ASU_coupled := 1;" make sure that the number, 'X', of "map_AC_to_ASU('Gas_CCS_AC_X') := 'ASU_X';" commands that are active matches the number of active Allam Cycle plants in the model save and close the procedure.

Co-firing technology at large power plants can contribute to reducing emissions and maintaining stable and secure electricity supplies. Due to the higher reactivity of biomass, a larger particle size range is generally used for biomass fuels compared with pulverized coal. A single particle apparatus has been developed for rapid heating and combustion of individual fuel particles. This wire mesh apparatus is used as a heating element to heat the particle by radiation while optical access allows particle combustion characterization by high speed camera recording. A woody biomass and a bituminous coal were used in this study. Both fuels showed a sequential combustion of volatile matter followed by char combustion. High speed video image analysis showed differences in ignition and devolatilization behaviour. The biomass volatile flame was smooth along the overall particle, while coal volatile matter release was delivered by jets. Times for the volatile matter combustion were much shorter for the coal while pyrolysis seemed to be the dominant step for around half of total combustion time. During devolatilization, the bituminous coal showed a significant swelling that was not seen in the biomass. As particle mass increased the overall times required for drying, devolatilization and burnout increased for both samples, and this was the dominant parameter to predict burnout time. Impact of particle size and mass was much higher in coal, with a dramatic increase in burnout times for particles above 300µm, while biomass particle size can have a greater range of sizes for the same burnout times. During biomass particle combustion, the results showed that the surface tension on the biomass char particle plays a significant role due to partial melting of the char particle. This effect modifies the char particle shape during its combustion, with particles becoming more spherical even for the initial fibrous shape of the woody biomass particles.

The flexible operation of CO2 injection wells presents significant challenges. To avoid premature degradation of wells or loss of integrity it is imperative to understand the feed flow patterns that future CO2 transportation and storage networks will face. We use a unit commitment economic dispatch (UCED) model to study CCS operating regimes in low carbon energy systems scenarios that are characterised by high shares of weather dependent renewable power generation. Using the case study of Great Britain, we determine the extent to which flexible operation of CCS plants is required, resulting in variable CO2 flows that need to be accommodated by future CO2 transportation and storage networks. We find that around 21% and 12% of the net flow rate changes over 6hperiods in the core scenario have greater amplitudes than 30% and 50% of nominal flow, respectively. When changes are averaged over two consecutive blocks of 6 h, representing the smoothing effect achievable via linepacking over a pipeline of reasonable length and diameter, around 9% of the net changes have greater amplitudes than 40% of nominal flow. Given the high and frequent fluctuations in feed flows across all considered scenarios, further research is urgently required on the capability of transportation and storage networks to accommodate variable CO2 flow rates.

This paper discusses considerations for the design of flexibly operated Carbon Capture and Storage (CCS) pipeline networks and is based on the findings of the Flexible CCS Network Development project (FleCCSnet), funded as part of the UK CCS Research Centre. The project considered the impact of flexibility across the whole CCS chain, as well as studying the interfaces between each element of the system; e.g. at the entry to the pipeline system from the capture plant and at the exit from the pipeline to the storage site. The factors identified are intended to allow CCS network designers to determine the degree of flexibility in the system; allowing them to react effectively to short, medium and long term variations in the flow of CO2 from capture plants and the constraints imposed on the system by CO2 injection and storage. The work of the project is reviewed in this paper which explores the flexibility of power plants operating with post combustion capture systems; quantifies the available time to store (line pack) CO2 in the pipeline as a function of pipeline size, the inlet mass flow rate and operating pressure; and explores the influence that uncertainty in injection and storage parameters have on the design of the pipeline. In addition, parameters influencing short and longer term network designs are discussed in terms of varying flow rates. Two practitioner workshops [1, 2] contributed to the direction of the project. The first workshop identified and confirmed key questions to be considered in order to understand the most likely impacts of variability in both the * Corresponding author. Tel.: +44 191 208 5532 E-mail address: ben.wetenhall@newcastle.ac.uk Available online at www.sciencedirect.com Ben Wetenhall et al. / Energy Procedia 114 ( 2017 ) 6800 – 6812 6801 CO2 sources and CO2 sinks on CO2 transport system design and operation. The second workshop focused on transient issues in the pipeline and storage site. Although the case studies in the work are UK based, this work is applicable to other situations where large and small sources of CO2 are expected to be feeding into a CCS transportation system. The work is expected to inform a broad range of stakeholders and allow network designers to anticipate potential problems associated with the operation of a CCS network. For an effective design of CCS infrastructure, all of the factors that will have a substantial impact on CO2 flow will have to be analysed at an early stage to prevent possible bottle necks in the whole chain. © 2017 The Authors. Published by Elsevier Ltd. Peer-review under responsibility of the organizing committee of GHGT-13.

Solvent storage has attracted wide interest as a possible way of increasing the profitability of postcombustion CCS power stations by adding an additional degree of operational flexibility to the underlying power plant. Solvent storage refers to the technique of delaying the energy-intensive step of solvent regeneration at post-combustion CCS power plants to later points in time in order to boost electrical output, and hence revenues, when electricity prices are high. This comes at the expense of needing to regenerate the stored rich solvent at a later point in time (i.e. energy penalty), as well as with the requirement for a comparatively large inventory of solvent (i.e. investment cost). An additional merit of solvent storage is the additional degree of freedom that is derived from decoupling electricity generation from the production of sequestration-ready CO2. Power plants that are fitted with the option of solvent storage can be used to balance CO2 flows feeding into transportation and storage systems in order to mitigate downstream issues arising from variable feed-flows [1-5]. Several authors have assessed the additional profits achievable with the option for solvent storage at post-combustion capture CCS power plants under historical and pre-defined price patterns (for electricity and CO2) [6-9]. Only one study [10], to the knowledge of the authors, has investigated the extent to which variable CO2 flows produced by load-following CCS power stations (coal-fired) can be smoothed out with the option for solvent storage (by decoupling electricity generation from the production of CO2). Looking at the profitability of solvent storage the general consensus is that whilst making the option available can recover the required upfront (relatively minor) investment, it does not lead to significant financial benefits in the longer term. A major drawback of most of these studies is, however, the amount of simplifying assumptions that are made in particular when it comes to underlying technical data. It is shown that depending on simplifications made the electricity and carbon price regions in which solvent storage is the profitable differ significantly. Figure 1-2 illustrates this by showing for different electricity and carbon price combinations the most profitable operating mode. Whilst solvent storage becomes profitable at around £72/MWh when common simplifying technical assumptions are used in the techno-economic analysis, this threshold decreases substantially to below £50/MWh under certain price combinations when the analysis is based on detailed technical modelling data.

This chapter first explores the different technologies and configurations used to attain carbon dioxide capture from biomass fuel sources, achieving negative net carbon emissions from biomass power. It compares post-combustion capture (based on air firing) and oxy-fuel combustion capture techniques. For post-combustion capture, a range of separation technologies can be utilised to remove the CO2 from the rest of the flue gas stream, including solvent-based (wet scrubbing) capture, which is assessed in detail, and membrane separation, which is overviewed briefly. The potential locations of steam extraction from the power plant to regenerate the capture solvents used for absorption are also considered. The relative merits of enriched-air firing and oxy-fuel options are evaluated through an assessment of flue gas recirculation configurations. As the nature of biomass is so dissimilar to that of fossil fuels in terms of composition and properties, the specific challenges associated with biomass utilisation under BECCS (biomass energy with carbon capture and storage) operating conditions are then outlined, focusing primarily on trace elements/impurities and their impacts on capture performance. The deployment potential of these various BECCS options is subsequently overviewed in light of these challenges, based on the technical knowledge which is summarised herein.