Capture Facility Research Articles

The <i>SCO<sub>2</sub>T</i> Database: Improved Estimates of Carbon Geologic Storage Costs and Resource Availability in Deep Saline Formations

We introduce the Sequestration of CO2 Tool (SCO2T) database, a collection of input and output data for geological storage in deep saline formations in the United States. Using the states participating in the Midwest Regional Carbon Initiative (https://www.midwestccus.org/), we introduce storage capacity and cost estimates for deep saline formations using SCO2T. The SCO2T database was created by members of Team SimCCS, a group of 25 researchers from 15 different institutions including commercial partners, universities, research institutions, national laboratories, governmental agencies, and NGOs. The SCO2T database will have an important role in pre-feasibility studies and site screening, particularly as it relates to coupling storage estimates with injection costs and matching ideal sink locations with capture facilities.

Experimental Study on Bubble Acoustic Characteristics of Elliptical Nozzles

Bubble acoustic signals were reported experimentally using five different nozzles with the same exit cross-sections. The bubble morphology was captured by a home-made experiment setup, which could synchronously obtain images of two perpendicular directions. Short-Time Fourier Transform and synchronization of video and audio were adopted to analyse the acoustic signal. Results demonstrated that the sound pressure of symmetrical bubble formation was higher than that of asymmetrical bubble formation, while the sound pressure of asymmetrical bubble formation was higher than that of the bubble with an unapparent necking fracture detached from the nozzle of the aspect ratio is 4:1. Furthermore, the last bubble of bubble chains would change the shape and decay rate of the acoustic signal due to the difference in the period of bubble formation. These studies can provide more effective information to predict the leaks from undersea gas pipelines, seabed methane reserves, and carbon capture and storage facilities.

Noble Gases as Monitoring Tracers in CCS: A Case Study with CO2 from the Waste-to-Energy Plant Klemetsrud, Norway

To design monitoring schemes for CO2 storage sites, the composition of the injected CO2 needs to be characterized. Noble gases are one of the environmental tracers, which could be cost-effective since they are naturally inherent in the CO2 and the storage reservoir fluids. The elemental, e.g. He/Ne, He/CO2, or isotopic, e.g. 3He/4He ratios of a gas are potentially diagnostic fingerprints which can be used to discriminate gas sources in the environment, e.g. deep crustal versus shallow, biogenic gas. The waste-to-energy (WtE) plant Klemetsrud, which generates 460000 tCO2/a, was investigated as a future source of captured CO2 for storage in the up-coming large-scale CCS project ‘Longship’, in Norway, aimed to be operational by 2024. In 2019, a demonstration capture facility at the WtE plant was set up to establish the feasibility of future large-scale CO2 capture. We sampled the main gas streams on-site and present the analysis of noble gases in (I) the exhaust of the waste incineration, i.e. the flue gas stream with high concentrations of CO2, (II) the capture outlet, i.e. the CO2-depleted gas stream and (III) the captured, concentrated CO2 gas stream. Noble gas concentrations are depleted in the captured CO2 after the amine treatment by several orders of magnitude compared to the flue gas. Isotopic ratios are air-like. This behavior has been observed at other CO2 capture plants. However, absolute concentrations of noble gases measured at Klemetsrud are significantly lower for all species, except He, which is within the range of previously measured concentrations. Further, we apply phase partitioning calculations to investigate the application of inherent noble gas in CCS monitoring schemes. The low noble gas concentrations, and their associated elemental and isotopic ratios, would only be preserved when the injected CO2 remains almost pure and does not mix or interact with fluids already present in the reservoir (e.g. native gas, formation water). Interaction of the CO2 with the formation water will lead to noble gas stripping that overprints the highly depleted composition of the captured CO2 with a noble gas elemental and isotopic ratios characteristic of deep crustal fluids. This characteristic signature, especially when coupled with the distinct major gas composition of leaked CO2 (e.g. extreme CO2/CH4 ratios) may form an effective tracer to discriminate a CO2 leakage from other gas sources at the seabed (e.g. shallow biogenic, dissolved air or hydrate decomposition). To take advantage of this low cost tracer, baseline geochemical surveys should include inventories of the background dissolved noble gas load in the formation water of storage reservoirs, in other (hydrocarbon bearing) formations along the migration route and in existing seabed gas seeps overlying the storage site.

Design and Costing of an ION Clean Energy CO2 Capture Plant Retrofitted to a 700 MW Coal-fired Power Station

ION Clean Energy’s (ION) advanced solvent is one of the leading solvent systems currently under development for post-combustion carbon dioxide (CO2) capture. ION has partnered with Nebraska Power Public District (NPPD), Sargent & Lundy (S&L), Koch Modular Process Systems (KMPS), and Siemens to design a commercial-scale (700 MW) capture system utilizing ION’s advanced solvent. The resulting CO2 capture plant design utilizes ION’s ICE 21 solvent and was designed to take full advantage of the solvent benefits, which include an efficient physical plant layout, reduced energy requirements, less solvent degradation, lower emissions, and lower capital costs relative to systems built with (U.S. Department of Energy) DOE Bituminous Baselines Study (BBS) case benchmark solvents. This Front-End Engineering and Design (FEED) is the continuation of a successful pre-FEED study on a 300 MW capture system at NPPD’s Gerald Gentleman Station (GGS) in Nebraska, USA, where cost of capture was determined to be approximately $32 per tonne of CO2. The overall objective of this project is to provide a detailed design resulting in an accurate cost estimate for a commercial-scale CO2 capture facility retrofitted onto a 700 MW existing coal-fired power station. The engineering design and costing will be provided at an Association for the Advancement of Cost Engineering (AACE) Class 2 estimate, which will result in cost accuracy in the range of 15 to +20%, supported by completion of up to 70% of the engineering effort. This paper reviews the engineering work completed to support the cost estimate, which includes process flow diagrams, utility flow diagrams, and general arrangement drawings. Balance of plant (BOP) engineering design was also completed to support the costing effort and includes the necessary tie-ins to the power station for steam, electricity, cooling water, makeup water, and flue gas. The culmination of this work is a 3D model of the carbon capture system as integrated at GGS. The 3D model incorporates the capture island and all the BOP modifications and necessary subsystems for the inclusion of the CO2 capture plant and ensure that the necessary level of detailed engineering has been achieved to support the cost estimate. A preliminary cost evaluation is discussed projecting the expected capital cost, operation and maintenance (O&M) cost, and cost of capture outcome based on the above engineering work. The CO2 capture rate efficiency was not confined or restricted for the FEED project but when optimized for this design basis remained at approximately 90% for full load operation. During the periods of turndown for the power plant, the CO2 capture efficiency increases to over 95% from the flue gas to fully utilize the installed equipment. This paper will also discuss the design and engineering challenges encountered while striving to integrate a CO2 capture system onto an existing power station. These challenges are not unique to this installation and include: • Sizing the system to best match the power station demands in a flexible power market • Designing a steam supply system that covers operations at all load conditions • Designing a heat rejection system with limited availability of cooling water resources and other factors that are site specific The project team has integrated several independent studies into this FEED project to address these specific challenges and this paper will review these results.

A Feasibility Study of Full Scale, Post Combustion, Amine Based, CO <sub>2</sub> Capture Retrofit Application in the Cement Manufacturing Sector at the Lehigh Hanson Materials Limited Facility

This paper will present the progress of a feasibility study, jointly conducted by Lehigh Hanson Materials Limited (Lehigh) and the International CCS Knowledge Centre, aimed at retrofitting a cement production facility at Lehigh (Edmonton, Alberta, Canada) with a full scale, post combustion, amine-based Carbon Dioxide (CO2) capture system. This study is a major breakthrough for carbon capture and storage (CCS) as it represents a first in North America for CCS application in the cement industry. The main deliverable of the feasibility study is a Class 4 estimate to assist Lehigh in determining the economic viability of a potential CCS retrofit project. This feasibility study commenced in November 2019 and will be complete in the fall of 2021 and is projected to cost $3.0M CAD. Funding for this study has been contributed to by Lehigh and Emissions Reduction Alberta (ERA) with contributions by the International CCS Knowledge Centre. The study will examine both the carbon capture technology and the “balance of plant”. Successful completion of this feasibility study could lead to a decision to carry out a Front End Engineering and Design (FEED) study and ultimately to a Final Investment Decision (FID) to implement a commercial scale project. A commercial project is projected to reduce emissions by approximately 600,000 tonnes of CO2 per year. The commercial scale project is projected to reduce emissions in Alberta in excess of 13.1 Mtonnes over a 25-year lifespan. The International CCS Knowledge Centre who is providing project management and advisory services, has engaged an experienced CO2 capture technology vendor, Mitsubishi Heavy Industries (MHI) Group, for the design of the CO2 capture system. MHI is responsible for the scope of work that includes the flue gas pretreatment system, the CO2 capture facility, and the CO2 compression process. The International CCS Knowledge Centre is also engaging and directing engineering consultants or other solution providers as appropriate. This direction and guidance will utilize base learnings from both the fully integrated Boundary Dam 3 CCS Facility and the comprehensive second-generation CCS study, known as the Shand CCS Feasibility Study, engineering consultants are being engaged to provide preliminary process and equipment design and cost estimates within their assigned scopes of work or work packages. The captured CO2 would be permanently sequestered and could be also used for Enhanced Oil Recovery (EOR). The Lehigh facility is located near potential storage locations, including being about 50 km away from the Alberta Carbon Trunk Line (ACTL) and nearby EOR opportunities. Lehigh, part of HeidelbergCement, will contribute to the company’s goal of achieving CO2-neutral concrete by 2050 at the latest and make it the most sustainable building material.

Technology Qualification to Mitigate Technical Risk in CCS Front End Engineering Design for the HeidelbergCement Norcem Plant

As part of the Norwegian full-scale CCS demonstration project “Longship”, Aker Carbon Capture conducted a FEED study for the CO2 capture facility at the Norcem plant in 2019. The CO2 capture facility design for the Norcem plant is based on Aker Carbon Capture’s proprietary ACCTM capture technology, which has been developed since 2005. A technology qualification was conducted during the Norcem CCS FEED study to assess the status and maturity of the ACCTM technology intended for use at the Norcem CO2 capture facility. The main purpose of the technology qualification was to reduce risk and to ensure that the plant will work as intended. The technology qualification followed the principles of the DNVGL-RP-A203 “Technology Qualification [9] and the DNVGL-RP-J201 “Qualification procedures for carbon dioxide capture technology” [10] recommended practices. Novel technology elements and the related, potential technological threats were identified and assessed. The risk associated with these were assessed to be low.

Design of steam-assisted temperature vacuum-swing adsorption processes for efficient CO2 capture from ambient air

Direct air capture (DAC) is an efficient, negative-carbon-emission technology that enables the capture of distributed emissions and removes location restrictions on capture facilities. However, current DAC demonstration plants are still too costly to be commercialized. In this work, a three-step steam-assisted temperature vacuum-swing adsorption (S-TVSA) cycle based on a packed column was designed for use in DAC systems, and the CO2 and H2O capacities and kinetics of the adsorbents were considered in detail. By operating the steam purge step at reduced pressures, steam at temperatures lower than 100 °C can be supplied by cheap thermal sources. In addition, the adsorption of H2O during the steam purge step can release heat for CO2 regeneration. Parameter sensitivity analysis reveals the trade-off relationship between the performance and energy consumption of DAC system with the S-TVSA cycle. The optimal case with a variational steam purge step operating at 90 °C and 0.3 bar achieves a CO2 productivity of 4.45 mol kg−1 day−1 and an energy requirement of 0.295 MJ mol−1. If the heat energy for the purge steam comes from solar energy or low-grade industrial waste heat, which represents 80.6% of the total energy consumption, the DAC system with S-TVSA cycle will be competitive with post-combustion CO2 capture technologies. Note that the productivity can be increased by up to 280% with only 32.8% of the initial energy consumption by using novel adsorbents with higher capacities and kinetics, potentially making S-TVSA cycles highly efficient for DAC systems.

Trace-level quantification of N-nitrosopiperazine in treated wastewater using supported liquid extraction and hydrophilic interaction chromatography mass spectrometry

Regenerable amine-based solvents used for post-combustion CO2 capture, primarily monoethanolamine and piperazine, are known to undergo degradation and secondary reactions over time forming, amongst other species, N-nitrosamines. These carcinogenic species can eventually make their way from treated wastewater into environmental waters. The United States Environmental Protection Agency (US EPA) recommends that the concentration of N-nitrosamines in surface water not exceed 1.24 μg/L. We have developed a straightforward method to quantify N-nitrosopiperazine in treated wastewater by hydrophilic interaction liquid chromatography – mass spectrometry (HILIC–MS) after sample preparation by supported liquid extraction (SLE). To achieve the best extraction recovery and method limits of quantification (MLOQ), standards were prepared in a high-salt synthetic matrix to mimic the treated wastewater effluent. To further improve the MLOQ, the drying steps after extraction were optimized. HILIC separation of the highly polar analytes was achieved using an ethylene-bridged hybrid amide stationary phase. Detection was achieved using a triple quadrupole mass spectrometer operated in positive electrospray ionisation and multiple reaction monitoring mode, providing a final MLOQ of 0.25 μg/L for N-nitrosopiperazine. Validation of the method was carried out to ensure good confidence in the data obtained for a treated wastewater sample from a post-combustion CO2 capture facility. In addition, N-nitrosopiperazine was quantified with the developed SLE-HILIC–MS method in eight degraded carbon capture samples that had not yet undergone wastewater treatment.

Simulation and optimisation of full-scale palm oil mill effluent (POME) treatment plant with biogas production

Palm oil mill effluent (POME) is the primary source of water pollution in the oil palm industry. Most palm oil mills are employing a series of anaerobic and aerobic ponds for POME treatment, in order to comply with environmental regulation. In recent years, some mills are installed with biogas capture facilities in order to reduce the emission of greenhouse gas, as well as to raise some profits. In this work, a covered lagoon process for POME treatment, coupled with biogas production was modelled using commercial process simulation software SuperPro Designer v9.0. The simulation results revealed that 29 m3 of biogas can be produced per tonne of treated POME, with a removal efficiency of 92 % for its chemical oxygen demand (COD). Cost analysis has proven that the process is economically viable, with a net present values of $ 2,830,000, IRR of 14.3 %, and payback time of 4.66 years. Process optimisation revealed that the optimal recycle ratio of sludge should be set to 30 %, where the minimum net expenditure ($11,812/y) is achieved, with final effluent COD content of 18 ppm. Note that this takes into consideration of the trade-off between capital and operating costs.

Intensified integrated direct air capture - power-to-gas process based on H2O and CO2 from ambient air

Solid sorbent based air capture facilities (DAC) of carbon dioxide can come along with high water co-adsorption. Integrating the latter in power-to-gas (PtG) concepts might reverse this disadvantage by using water separated from air as a feedstock for electrolysis based hydrogen production. Investigation of the overall integrated system by detailed simulation reveals the possibility of realizing high degrees of synergies within the strongly coupled DAC-PtG process. Efficient water recovery can reduce the process water demand by a factor of 4. Focusing on the overall energy demand, detailed pinch analysis of the integrated DAC-PtG concept is performed. High temperature water condensation allows for heat recovery in the order of 1.5 times the heat of reaction released in methanation process. Electrolysis operation point was found to be of high importance. Operation at 1.5 equilibrium cell voltage results in excess heat production of 475 kJ per mole CO2 captured, whereas at equilibrium cell voltage process heat demand of 16 kJ mol−1 is observed. Overall, the possibility of designing an autothermally operated process for the production of methane based on carbon dioxide and water from ambient air is confirmed, where the synergies between the process sections revealed are of interest for general power-to-X (PtX) applications.

Photoassisted salt-concentration-biased electricity generation using cation-selective porphyrin-based nanochannels membrane

Abstract Natural sunlight is one kind of renewable energy that is considered likely to be ubiquitous at the river-sea junction. Ingeniously engineering a photoassisted enhanced electricity capture facility based on an artificial nano-porous membrane, is a necessity. Herein, a proof-of-concept system is constructed, wherein cation-selective photoresponsive porphyrin/alumina nanochannels are entrusted with cationic selectivity and extraordinary photoelectric response, thus it is available to synergistically convert salinity gradient and solar energy into high electric energy. Depending solely on excellent cationic selectivity of nanochannels, the salinity-gradient-driven membrane system can capture high power output of 2.16 W/m2. And harvested power of the generator with the help of photo is elevated to 4.56 W/m2. Resulted total transmembrane ionic current (Itotal) is traceable to a smooth cooperative effort of diffusion current (Idiff) and photo-induced ionic current (Iphoto). Benefiting from the accumulation characters of ionic current, the electricity generator with the modulation of concentration gradient and varying-intensity photo stimulus can achieve a multivalued conduction including current and power increase. The general nanofluidic system paves the way for other multi-functional membranes that simultaneously utilize various clean sources to potentially improve entire electricity output.

Energy and Economic Costs of Chemical Storage

The necessity of neutralizing the increase of the temperature of the atmosphere by the reduction of greenhouse gas emissions, in particular carbon dioxide (CO2), as well as replacing fossil fuels, leads to a necessary energy transition that is already happening. This energy transition requires the deployment of renewable energies that will replace gradually the fossil fuels. As the renewable energy share increases, energy storage will become key to avoid curtailment or polluting back-up systems. This paper considers a chemical storage process based on the use of electricity to produce hydrogen by electrolysis of water. The obtained hydrogen (H2) can then be stored directly or further converted into methane (CH4 from methanation, if CO2 is available, e.g. from a carbon capture facility), methanol (CH3OH, again if CO2 is available), and/or ammonia (NH3 by an electrochemical process). These different fuels can be stored in liquid or gaseous forms, and therefore with different energy densities depending on their physical and chemical nature. This work aims at evaluating the energy and the economic costs of the production, storage and transport of these different fuels derived from renewable electricity sources. This applied study on chemical storage underlines the advantages and disadvantages of each fuel in the frame of the energy transition.

Implementing a second generation CCS facility on a coal fired power station – results of a feasibility study to retrofit SaskPower's Shand power station with CCS

AbstractIn 2018, the International CCS Knowledge Centre (CCS Knowledge Centre) conducted a feasibility study with SaskPower to determine if a business case could be made for a postcombustion, carbon capture retrofit of SaskPower's Shand Power station, a 305‐MW, single‐unit, lignite coal‐fired power station located near Estevan, Saskatchewan. Specifically, Mitsubishi heavy industries’ KM CDR technology was evaluated for this study. While no decision has been made, should SaskPower decide to proceed, the Shand carbon capture and storage (CCS) project would produce the second, full‐scale capture facility in Saskatchewan with a nominal capacity of 2 million tonnes of CO2 (Mt) per year. This paper summarizes the key technical and economic findings of this study. Notably this study found that the capital costs of the potential Shand CCS facility are decreased by 67% on a per tonne of CO2 captured basis when compared to the CCS retrofit of Unit 3 at the Boundary Dam Power Station (the world's first industrial scale CCS installation on a coal fired power station). The proposed capture facility would also have a load following operational profile, reduction in parasitic loses by employing heat integration strategies, and need no additional water draw to provide the required increase in cooling duty. © 2020 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons, Ltd.

Bench-Scale Demonstration of Molten Alkali Metal Borates for High-Temperature CO2 Capture

The molten alkali metal borates represent an opportunity for carbon dioxide capture and the on-going challenge of adapting to a carbon-constrained world with the immediacy of climate change. We demonstrate the performance of this new class of materials at the bench scale, highlighting the ability to operate isothermally at high temperatures through the use of steam as a sweep gas. Breakthrough curves for a wide set of conditions are presented and linked to the sorbents’ underlying thermodynamic and kinetic properties. We demonstrate the ability to capture over 99.9% of incoming CO2 even at low concentrations or to capture ∼90% CO2 under high flow rates and utilize a greater portion of the sorbent capacity. The advantages of the molten alkali metal borates scale well, and their unique position as high-temperature liquid phase sorbents may enable new process designs for efficient low-cost CO2 capture facilities.

A multicut outer-approximation approach for competitive facility location under random utilities

This work concerns the maximum capture facility location problem with random utilities, i.e., the problem of seeking to locate new facilities in a competitive market such that the captured demand of users is maximized, assuming that each individual chooses among all available facilities according to a random utility maximization model. The main challenge lies in the nonlinearity of the objective function. Motivated by the convexity and separable structure of such an objective function, we propose an enhanced implementation of the outer approximation scheme. Our algorithm works in a cutting plane fashion and allows to separate the objective function into a number of sub-functions and create linear cuts for each sub-function at each outer-approximation iteration. We compare our approach with the state-of-the-art method and, for the first time in an extensive way, with other existing nonlinear solvers using three data sets from recent literature. Our experiments show the robustness of our approach, especially on large instances, in terms of both computing time and number instances solved to optimality.

Demonstrating flexible operation of the Technology Centre Mongstad (TCM) CO2 capture plant

This study demonstrates the feasibility of flexible operation of CO2 capture plants with dynamic modelling and experimental testing at the Technology Centre Mongstad (TCM) CO2 capture facility in Norway. This paper presents three flexible operation scenarios: (i) effect of steam flow rate, (ii) time-varying solvent regeneration, and (iii) variable ramp rate. The dynamic model of the TCM CO2 capture plant developed in gCCS provides further insights into the process dynamics. As the steam flow rate decreases, lean CO2 loading increases, thereby reducing CO2 capture rate and decreasing absorber temperature. The time-varying solvent regeneration scenario is demonstrated successfully. During “off-peak” mode (periods of low electricity price), solvent is regenerated, reducing lean CO2 loading to 0.16 molCO2/molMEA and increasing CO2 capture rate to 89–97%. The “peak” mode (period of high electricity price) stores CO2 within the solvent by reducing the reboiler heat supply and increasing solvent flow rate. During peak mode, lean CO2 loading increases to 0.48 molCO2/molMEA, reducing CO2 capture rate to 14.5%, which in turn decreases the absorber temperature profile. The variable ramp rate scenario demonstrates that different ramp rates can be applied successively to a CO2 capture plant. By maintaining constant liquid-to-gas (L/G) ratio during the changes, the CO2 capture performance will remain the same, i.e., constant lean CO2 loading (0.14–0.16 molCO2/molMEA) and CO2 capture rate (87–89%). We show that flexible operation in a demonstration scale absorption CO2 capture process is technically feasible. The deviation between the gCCS model and dynamic experimental data demonstrates further research is needed to improve existing dynamic modelling software. Continual development in our understanding of process dynamics during flexible operation of CO2 capture plants will be essential. This paper provides additional value by presenting a comprehensive dynamic experimental dataset, which will enable others to build upon this work.

Utilizing Steering Entropy as a Measure of Performance in Head-mounted Augmented Reality

The next phase of augmented reality (AR) technologies suggest that as both the hardware and software continue to improve, we can expect that AR will become more commonly used as a tool for a variety of applications in complex operational contexts (i.e. training, manufacturing, mission planning). As new applications are designed and developed within these contexts, there is a necessity to be able to measure the effectiveness of these systems and to understand their impact on human performance and workload, so that only the most appropriate designs are selected for use, growing the technology in usefulness, not novel hindrances. A unique opportunity presented by the Microsoft HoloLens platform, as an example of head-worn AR systems, is the ability to collect positional and movement data, which lends itself to the computation of behavioral (or steering) entropy data, which can be related to human workload and performance within the system environment. However, little reference exists to be able to verify the accuracy of tracking of the device with regards to the output data available for collection. Within this practitioner-oriented paper, we extend current entropy measurement theory typically used in control settings within a heads-up display type ‘controls' environment. Our findings indicate that in-situ measurements of entropy utilizing the onboard sensors within the AR platform are more accurate to those collected within a Motion Capture Facility. Extending this work, these measurements can be used as a correlate of performance.

On the Noise Complexity in an Optical Motion Capture Facility.

Optical motion capture systems are state-of-the-art in motion acquisition; however, like any measurement system they are not error-free: noise is their intrinsic feature. The works so far mostly employ a simple noise model, expressing the uncertainty as a simple variance. In the work, we demonstrate that it might be not sufficient and we prove the existence of several types of noise and demonstrate how to quantify them using Allan variance. Such a knowledge is especially important for using optical motion capture to calibrate other techniques, and for applications requiring very fine quality of recording. For the automated readout of the noise coefficients, we solve the multidimensional regression problem using sophisticated metaheuristics in the exploration-exploitation scheme. We identified in the laboratory the notable contribution to the overall noise from white noise and random walk, and a minor contribution from blue noise and flicker, whereas the violet noise is absent. Besides classic types of noise we identified the presence of the correlated noises and periodic distortion. We analyzed also how the noise types scale with an increasing number of cameras. We had also the opportunity to observe the influence of camera failure on the overall performance.

Piperazine aerosol mitigation for post-combustion carbon capture

Amine loss as aerosol is still a challenge for reliable long-term operations in amine scrubbing units. While attempts have been made to understand, predict, and mitigate amine aerosol growth in the absorber, demonstration of the mitigation of piperazine (PZ) aerosol has not been published. This paper presents results from a comprehensive emission study using 5 m PZ. The focus of this work is not to validate growth mechanisms, but to provide data from which existing hypotheses can be analyzed. PZ aerosol at the water wash outlet was characterized by Fourier Transform Infrared Spectroscopy (FTIR) and an Electrical Low-Pressure Impactor (ELPI+). Two mitigation strategies were successfully implemented during episodes of PZ aerosol emission. These episodes resulted from the presence of SO3 in the flue gas due to periods of sub-optimal SO3 removal upstream of the CO2 capture facility. Four weeks of aerosol tests were also run with 0–6 ppm of SO3 generated and injected into the flue gas to evaluate the resilience of the mitigation strategies. The first approach to aerosol emission mitigation was to remove aerosol nuclei present in the flue gas. The second approach was to run the absorber with flue gas containing varying SO3 at conditions that accelerate aerosol nuclei growth and collection within the packing. SO3 control via hydrated lime addition upstream of the absorber eliminated aerosol while higher lean solvent temperature in the absorber and a two-stage water wash configuration were tested to accelerate aerosol nuclei growth and collection. Increasing the lean solvent temperature by 11 °C and using a two-stage water wash resulted in 98% reduction of PZ emissions. Absorber performance at the elevated lean solvent temperature was sustained in the existing packing with solvent intercooling. PZ emissions were managed to less than 1 ppm for extended periods during the pilot plant campaign.

Deploying gas power with CCS: The role of operational flexibility, merit order and the future energy system

Combined cycle gas turbine (CCGT) power plants are an important part of many electricity systems. By fitting them with carbon capture their CO2 emissions could be virtually eliminated. We evaluate CCGT plants with different variations of post combustion capture using amine solvents, covering a range of options, including solvent storage, partial capture and shifting the energy penalty in time. The analysis is based on the UK electricity system in 2025. The behaviour of individual CCGT plants is governed by the plant’s place in the merit order and to a lesser extent by CO2 reduction targets for the electricity system. In the UK, CCGT plants built from 2016 onwards will emit ∼90% of the CO2 emissions of the whole CCGT fleet in 2025. The typical ‘base case’ CCGT plant with capture is designed to capture 90% of the CO2 emissions and to operate dynamically with the power plant. Downsizing the capture facility could be attractive for low-merit plants, i.e. plants with high short-run marginal costs. Solvent storage enables electricity generation to be decoupled in time from the energy penalty associated with carbon capture. Beyond a few minutes of solvent storage, substantial tanks would be needed. If solvent storage is to play an important role, it will require definitions of ‘capture ready’ to be expanded to ensure sufficient land is available.