This study geochemically characterized a proposed Carbon Capture and Storage project in northeast British Columbia, and presents new dissolution kinetics data for the proposed saline aquifer storage reservoir, the Keg River Formation. The Keg River Formation is a carbonate reservoir (89-93% Dolomite, 5-8% Calcite) at approximately 2200 m depth, at a pressure of 190 bar, and temperature of 105 °C. The Keg River brine is composed of Na, Cl, Ca, K, Mg, S, Si, and HCO3 and is of approximately 0.4 M ionic strength. Fluid analysis found the Keg River brine to be relatively fresh compared with waters of the Keg River formation in Alberta, and to also be distinct from waters in overlying units. These findings along with the physical conditions of the reservoir make the Keg River Formation a strong candidate for CO2 storage. Further work measured the dissolution rates of Keg River rock that will occur within the Keg River formation. This was performed in a new experimental apparatus at 105 °C, and 50 bar pCO2 with brine and rock sampled directly from the reservoir. Dissolution rate constants (mol!m-2s-1) for Keg River rock were found to be Log KMg 9.80 ±.02 and Log KCa -9.29 ±.04 for the Keg River formation. These values were found to be significantly lower compared to rate constants generated from experiments involving synthetic brines with values of Log KMg -9.43 ±.09, and Log KCa -9.23 ±.21. Differences in rates were posited as due to influences of other element interactions with the >MgOH hydration site, which was tested through experiments with brines spiked with SrCl2 and ZnCl2. Results for the SrCl2 spiked solution showed little impact on dissolution rates with rate constants of Log KMg -9.43 ±.09, and Log KCa -9.15 ±.21, however the ZnCl2 spiked solution did show some inhibition with rate constants of Log KMg -9.67 ±.04, and Log KCa -9.30 ±.04. Rate constants generated in this work are among the first presented which can actually be tested by full-scale injection of CO2. / Graduate

A model for the evaluation of CO2-EOR projects has been developed. This model includes both reservoir simulation to handle reservoir properties, fluid flow and injection and production schedules, and a numerical economic model that generates a monthly cash flow stream from the outputs of the reservoir model. This model is general enough to be used with any project and provide a solid common basis to all of them. This model was used to evaluate CO2-EOR injection and production strategies and develop an optimization workflow. Producer constraints (maximum oil and gas production rates) should be optimized first to generate a reference case. Further improvements can then be obtained by optimizing the injection starting date and the injection plateau rate. Investigation of sensitivity of CO2-EOR to the presence of an aquifer showed that CO2 injection can limit water influx in the reservoir and is beneficial to recovery, even with a strong water drive. The influence of some key parameters was evaluated: the producer should be completed in the top part of the reservoir, while the injector should be completed over the entire thickness; it is recommended but not mandatory that the injection should start as early as possible to allow for lower water cut limit. Finally, the sensitivity of the economics of the projects to some key parameters was evaluated. The most influent parameter is by far the oil price, but other parameters such as the CO2 source to field distance, the pipeline cost scenario, the CO2 source type or the CO2 market price have roughly the same influence. It is therefore possible to offset an increase of one of them by reducing another.

Flexible carbon capture and storage (CCS) has the potential to play a significant part in the decarbonisation of electricity generation portfolios which have significant penetration from intermittent renewable sources. Post-combustion capture (PCC) with amine solvents is a mature technology and is currently the state-of-the-art for CO2 emissions reduction from power stations. However, knowledge of the dynamic capture process is currently limited due to a dearth of dynamic datasets which reflect real plant operation, lack of a robust in-situ solvent analysis method for plant control and uncertainty about how changing plant design affects the response to dynamic operations. In addition, the nature of interfacial gas-liquid dynamics inside the absorber column are not well known and rely on correlations for effective mass transfer area and liquid holdup which may have uncertainties of up to +/- 13%. This could result in absorption columns being improperly sized for CCS operations. Two pilot-scale test campaigns are implemented in order to gain an understanding of how the capture plant responds to dynamic operations, the first on natural gas combined cycle (NGCC)-equivalent flue gas, the second on pulverised coal (PC)-equivalent. Changes in flue gas flow rates and steam supply which are designed to be representative of PCC operation on real NGCC and PC plant are implemented, using 30%wt monoethanolamine (MEA) as absorbent in both cases. Dynamic datasets are obtained for 5 scenarios with NGCC and 8 with PC flue gas. The test campaigns are carried out using two separate pilot-scale facilities and highlight the effect of plant design on hydrodynamics and hence, the response of the capture plant to dynamic operations. Finally, a novel solvent sensor is used to demonstrate, for the first time, control of the capture facility using in-situ measurements of solvent composition, combined with knowledge of test facility hydrodynamics and response times. Results from the pilot-scale test campaign are then used along with a mathematical NGCC capture plant scale up to investigate the potential effects of dynamic operations on total yearly CO2 emissions and the associated environmental penalties, depending on CO2 price. Manufacturers of column internals for CCS often rely on computational fluid dynamic (CFD) software tools for design, but existing commercial codes are unable to handle complex two-phase flows such as those encountered in the absorber column of a CO2 capture plant. An open-source direct numerical simulation (DNS) tool which will be capable of rigorously modelling two-phase flow with turbulence and mass transfer has been developed and could eventually replace the empirical methods currently used in packing design. The DNS code requires validation by experiment. For the purpose of validation a dual-purpose wetted-wall column is constructed, which in addition to mass transfer measurements can be used to determine liquid film thickness using an optical method. Measurements of average film thickness, wave amplitude, frequency, velocity and growth rate are provided for three liquid flow rates of fresh 30%wt MEA solution. Wave measurements are made with quiescent, laminar and turbulent gas flow, with and without mass transfer. These measurements can be used to validate the DNS code at its existing level of complexity, and in the future when turbulence and mass transfer are added.

I assess the potential of seismic and time-domain controlled-source electromagnetic (CSEM) methods to monitor carbon dioxide (CO2) migration through the application of a monitorability workflow. The monitorability workflow describes a numerical modelling approach to model variations in the synthetic time-lapse response due to CO2 migration. The workflow consists of fluid-flow modelling, rock-physics modelling and synthetic seismic or CSEM forward modelling. I model CO2 injected into a simple, homogeneous reservoir model before applying the workflow to a heterogeneous model of the Bunter Sandstone reservoir, a potential CO2 storage reservoir in the UK sector of the North Sea. The aim of this thesis is to model the ability of seismic and time-domain CSEM methods to detect CO2 plume growth, migration and evolution within a reservoir, as well as the ability to image a migrating front of CO2. The ability to image CO2 plume growth and migration within a reservoir has not been demonstrated in the field of CSEM monitoring. To address this, I conduct a feasibility study, simulating the time-lapse CSEM time-domain response of CO2 injected into a saline reservoir following the multi-transient electromagnetic (MTEM) method. The MTEM method measures the full bandwidth response. First, I model the response to a simple homogeneous 3D CO2 body, gradually increasing the width and depth of the CO2. This is an analogue to vertical and lateral CO2 migration in a reservoir. I then assess the ability of CSEM to detect CO2 plume growth and evolution within the heterogeneous Bunter Sandstone reservoir model. I demonstrate the potential to detect stored and migrating CO2 and present the synthetic results as time-lapse common-offset time sections. The CO2 plume is imaged clearly and in the right coordinates. The ability to image seismically a migrating front of CO2 remains challenging due to uncertainties regarding the pore-scale saturation distribution of fluids within the reservoir and, in turn, the most appropriate rock-physics model to simulate this: uniform or patchy saturation. I account for this by modelling both saturation models, to calculate the possible range of expected seismic velocities prior to generating and interpreting the seismic response. I demonstrate the ability of seismic methods to image CO2 plume growth and evolution in the Bunter Sandstone saline reservoir model and highlight clear differences between the two rock-physics models. I then modify the Bunter Sandstone reservoir to depict a depleted gas field by including 20% residual gas saturation. I assess the importance and implication of patchy saturation and present results which suggest that seismic techniques may be able to detect CO2 injected into depleted hydrocarbon fields.

Environmental concerns about the effect of greenhouse gases have led governments to regulate industrial CO2 emissions, including through emissions caps, trading and penalties, thus creating economic incentives to reduce CO2 emissions. This research focuses on strategies to reduce CO2 emissions from energy systems in the context of the process industries. In the process industries, energy systems consume fuel to generate steam and power for site process units. Improving energy efficiency can reduce costs of energy generation and use, as well as CO2 emissions. This research develops an integrated design and optimisation methodology for energy systems, allowing effective capture and control of carbon dioxide emissions. The first focus of this study is to develop a systematic approach to evaluate combinatorial strategies for reducing CO2 emissions, based on a techno-economic analysis. A conceptual design procedure with hierarchical decision-making is introduced to combine CO2 emissions reduction strategies, accounting for interactions between site components, including the heat exchanger network and utility system. CO2 emissions reduction options considered in development of this procedure include process integration techniques for improving the energy efficiency of the site and fuel switching. The proposed approach considers trade-offs between the economy of energy retrofit and CO2 emissions penalties. Opportunity for reducing the CO2 penalty is included in the economic evaluation of the combined emissions reduction strategies. A mathematical model for simultaneous optimization of emissions reduction strategies is developed. In addition to emissions reduction strategies, options for trading CO2 allowances are considered in the model. The proposed mathematical method applies Mixed Integer Non Linear Programming (MINLP) optimization, which employs a superstructure of the strategies for CO2 reduction. The proposed mathematical model relates the selected options to their operating and capital costs and to their associated CO2 emissions, allowing the optimizer to search for the optimal combination of emissions reduction strategies. While the reduction in CO2 emissions through process integration techniques is based on the existing configuration of a site and the associated structural limitations, integration of Carbon Capture and Storage (CCS) technologies can provide greater mitigation of CO2 emissions from a site. However, important challenges of implementing CCS in the process industries are the energetic and economic impact of the CCS plant on the integrated site. In the second part of this study, these energy-economic issues are explored. The CCS technologies addressed in this thesis include post- and pre-combustion CO2 capture techniques. Simulation of each capture technique is carried out in process simulation software to characterize the energy performance of the CO2 capture plant. Sensitivity analyses are carried out for key parameters of the CO2 capture plant. The relationship between these key parameters and the energy balance of the capture plant is represented using a simple energy performance model for the CO2 capture plant. This model allows the integration of the CO2 capture plant with the site utility system to be explored. Interactions between the utility system and CO2 capture plant are considered. The site utility system, together with the CO2 capture plant, is optimized for minimum operating cost. The proposed procedures are illustrated by application to a case study of a medium-scale oil refinery. The results illustrate that to reduce CO2 emissions, heat integration, utility system optimization and fuel switching provide more cost-effective solutions than integrating CCS technologies. The mathematical model allows more cost-effective solutions to be identified than using sequential, conceptual methods, but the value of the conceptual method for developing insights is also illustrated. The results demonstrate that, depending on the potential of the site for increasing heat recovery and the type of fuel used on site, solutions that combine energy efficiency and fuel switching can provide up to 40% reduction in site CO2 emissions. Integrating a post-combustion CO2 capture plant with the site utility system can provide up to 90 mol% pure CO2 for sequestration; however, the high capital cost of the capture plant reduces the economic performance of the integrated site. The high heat demand of post-combustion CO2 capture for solvent regeneration increases the fuel consumption of the site and its utility system, which in turn reduces the recovery of CO2. The results reveal that pre-combustion CO2 capture can provide opportunities for heat and power generation to improve the techno-economic performance of the overall integrated site.

The ultimate goal of this project is to comprehensively investigate induced seismicity potential by studying the behavior of fault shear zones during high pressure CO2 injection for utilization and storage operations. Seismicity induced by fluid injection is one of the major concerns associated with recent energy technologies such as Carbon capture and storage (CCS) projects. CO2 injection increases reservoir pore pressure and decreases the effective stress causing deformation that can degrade the storage integrity by creating new fractures and reactivating faults. The first consequence is that reactivation of faults and fractures create a pathway for upward CO2 migration. The increased seismic activity is the second consequence, which raises the public concern despite the small magnitudes of such earthquakes. Changes in pore fluid pressure within the injection zone can induce low-magnitude seismic events. However, there are multiple involved Thermo-Hydro-Mechanical (THM) processes during and after fault slip that influences pore pressure and fault strength. Flash heating and thermal pressurization are two examples of such processes that can weaken the fault and decrease frictional resistance along the fault. The proposed study aims to use a multi-physics numerical simulation to analyze the fault shear zone mechanics and capture the involved THM processes during CO2 injection. In one study, a coupled THM model is performed to simulate stress and pore pressure changes in the fault and ultimately measuring the maximum induced magnitude. The other study investigates the response of the fault shear zone during CO2 injection with and without considering the thermal pressurization (TP) effect. In the third part, the realistic behavior of friction was studied by using a rate-and-state friction theory to capture the full earthquake rupture sequence. The outcome of the proposed project can significantly increase the efficiency and public acceptance of CCS technology by addressing the major concerns related to the induced seismicity due to CO2 injection.

The Carbon Capture and Storage method has been acknowledged for the capabilities of reducing up to 20% CO2 emissions. Development of porous carbon materials prepared from polyurethane foam adsorbent were investigated for capture of CO2. In this thesis work, the carbon material was chemically activated through the direct and indirect methods. Pre-carbonization, mass ratio KOH/char, activation temperature, and activation time, the effect of the preparation conditions on the porous adsorbent were evaluated for the purpose of managing pore sizes and developing high adsorption capacity of CO2. During the direct method, polyurethane foam was directly treated with KOH before activation. Whereas during the indirect method, the foam was pre-carbonized to form char, which was treated instead. The indirectly and directly activated adsorbent prepared at optimum conditions show adsorption capacities of 152,10 and 151,29 mg/g at 1 atm and 25°C respectively. The produced adsorbents were evaluated for their CO2 separation performance with a thermogravimetric analyser with 100% CO2. The CO2 uptake and pore sizes were directly affected by the different parameters. A moderate activation time and temperature presented a higher adsorption capacity, where it decreased after reaching a higher time and temperature. A higher KOH/char mass ratio leads to a higher CO2 uptake, where it steadily increases from the lowest mass ratio.

Since 1996, super-critical CO$_2$ has been injected at a rate of $\sim$0.85~Mt~yr$^{-1}$ into a pristine, saline aquifer at the Sleipner carbon capture and storage project. A suite of time-lapse, three-dimensional seismic reflection surveys have been acquired over the injection site. This suite includes a pre-injection survey acquired in 1994 and seven post-injection surveys acquired between 1999 and 2010. Nine consistently bright reflections within the reservoir, mapped on all post-injection surveys, are interpreted to be thin layers of CO$_2$ trapped beneath mudstone horizons. The areal extents of these CO$_2$ layers are observed to either increase or remain constant with time. However, volume flux of CO$_2$ into these layers has proven difficult to measure accurately. In addition, the complex planform of the shallowest layer, Layer 9, has proven challenging to explain using reservoir simulations. In this dissertation, the spatial distribution of CO$_2$ in Layer~9 is measured in three dimensions using a combination of seismic reflection amplitudes and changes in two-way travel time between time-lapse seismic reflection surveys. The CO$_2$ volume in this layer is shown to be growing at an increasing rate through time. To investigate CO$_2$ flow within Layer~9, a numerical gravity current model that accounts for topographic gradients is developed. This vertically-integrated model is computationally efficient, allowing it to be inverted to find reservoir properties that minimise differences between measured and modelled CO$_2$ distributions. The best-fitting reservoir permeability agrees with measured values from nearby wells. Rapid northward migration of CO$_2$ in Layer~9 is explained by a high permeability channel, inferred from spectral decomposition of the seismic reflection surveys. This numerical model is found to be capable of forecasting CO$_2$ flow by comparing models calibrated on early seismic reflection surveys to observed CO$_2$ distributions from later surveys. Numerical and analytical models are then used to assess the effect of the proximity of an impermeable base on the flow of a buoyant fluid, motivated by the variable thickness of the uppermost reservoir. Spatial gradients in the confinement of the reservoir are found to direct the flow of CO$_2$ when the current is of comparable thickness to the reservoir. Finally, CO$_2$ volume in the second shallowest layer, Layer~8, is measured using structural analysis and numerical modelling. CO$_2$ in Layer~8 is estimated to have reached the spill point of its structural trap by 2010. CO$_2$ flux into the upper two layers is now $\sim$40\% of total CO$_2$ flux injected at the base of the reservoir, and is increasing with time. This estimate is supported by observations of decreasing areal growth rate of the lower layers. The uppermost layers are therefore expected to contribute significantly to the total reservoir storage capacity in the future. CO$_2$ flow within Layer~9 beyond 2010 is forecast to be predominantly directed towards a topographic dome located $\sim$3~km north of the injection point. This dissertation shows that advances in determining the spatial distribution and flow of CO$_2$ in the sub-surface can be made by a combination of careful seismic interpretation and numerical flow modelling.

The Paris Agreement aims to limit global warming to 1.5 degrees Celsius, and Sweden has set a goal toreach net-zero emissions by 2045. Carbon Capture and Storage (CCS) is one method that can reducecarbon dioxide emissions. The industry and transportation sectors are the biggest sources of emissionsin Sweden, requiring technological developments and increased investment to reduce their carbondioxide (CO2) emissions. The Geological Survey of Sweden (SGU) is responsible for controls,supervision, operation, and construction of activities connected with carbon dioxide (CO2) storage. SGUbelieves that the storage conditions in Sweden are poor. Sedimentary, basaltic and ultramafic rock ispreferable for CO2 storage, but finding the right sort of bedrock at the right depth and with the rightvolumes and porosity is the challenge. Hence it is in question to collaborate with nations in the northern sea, in order to transport and storageCO2 which would lessen the burden of needing to build new infrastructure. There are a few upcomingCarbon Capture and Utilisation (CCU) projects in Sweden but from the industry’s point of view, thepriority seems to be mostly on Bio-CCS. However, there is still interest for CCS technology in industrialproduction such as steel or cement and also Direct Air Capture (DAC) in the near future. Due to thehigh cost of CCS, funding through the Swedish Energy Agency and EU is vital in order to make iteconomically viable. Other Cost reducing solutions such as relocation on old oil and gas fields orarranging CCS hubs are possible. In summary, this study concludes that CCS is not currently a feasible technique in order to reduce CO2 from the atmosphere, given the current state and costs for it. If the technology becomes more energyefficient and when financial means are in place, the future is bright for CCS. It is extremely relevantthat this technology continues to develop into a better, cheaper and faster way to capture CO2 and reduceemissions of the effective greenhouse gases. / Parisavtalet syftar till att begränsa den globala uppvärmningen till 1,5 grader Celsius och Sverige harockså satt som mål att nå nettonollutsläpp till år 2045. Ett sätt att nå dessa mål kan vara med teknikenför Carbon Capture and Storage (CCS) som är en metod för att minska koldioxidhalten i atmosfären.Den här rapporten syftar till att undersöka med hjälp av litteraturstudier och intervjuer hur genomförbarCCS är som teknik för att minska koldioxidutsläppen samt hur man även kan minska på den befintligamängden koldioxid som redan finns i luften. Huvudfokuset är att undersöka hur CCS fungerar och vilkakostnader som är involverade. Eftersom koldioxid (CO2) är en av de växthusgaser som bidrar mest tillden globala uppvärmningen är det viktigt att vidta åtgärder för att minska den. Det är inte bara utsläppenav CO2 som måste minska utan även mängden CO2 som redan finns i atmosfären. Forskning kring CCSär därför viktig för att hitta nya sätt att effektivisera metoden och göra den mer genomförbar. Naturvårdsverket ger ut en årlig rapport som utvärderar landets framsteg mot att nå sina miljömål,inklusive “Begränsad klimatpåverkan”. Rapporten konstaterar att även om EU och Sverige har minskatutsläppen ökar de fortfarande globalt sett. Industri- och transportsektorn identifieras som de störstautsläppskällorna i Sverige. Den svenska förordningen om CCS regleras av miljöbalken som testar kollagringi geologiska formationer som en miljöfarlig verksamhet och den separerade CO2 ses som avfall.Sverige har ännu inte någon kommersiell CCS-anläggning men regeringen har föreslagit att svenskaindustrier bör införa CCS för att minska dessa utsläpp. Både Sverige och EU har investerat i att utvecklateknik för att minska användningen av fossila bränslen och underlätta för användningen av CCS. CCS processen består av tre huvudsteg: avskiljning och separering av CO2, transport samt lagring elleråteranvändning. Alla typer av nuvarande CCS-metoder kräver en stor mängd energi och de flesta avdem separerar CO2 från industriella förbränningar. Direct Air Capture (DAC) är en annaninfångningsteknik som är mer flexibel när det gäller placering, men också dyrare än de andra teknikerna.Transporten av den infångade CO2 kan ske med lastbil, tåg, fartyg eller rör. De mest genomförbaraalternativen är dock rörledningar och via fartyg på grund av deras transportkapacitet. Rörledningarkräver en välutvecklad infrastruktur, vilket gör dem kostsamma, men de är det mest genomförbaraalternativet för att separera CO2 från landbaserade anläggningar och transportera dem till närliggandelagringsplatser. Geologisk lagring av CO2 kan göras både på land och till havs. Injektion till dengeologiska formationen vid lagringsplatser sker via borrhål. CO2 förvätskas och ersätter denursprungliga vätskan i bergmaterialets porer i berggrunden och reagerar så småningom med berget ochbildar nya mineraler i berggrunden. Sveriges Geologiska Undersökning (SGU) ansvarar för kontroller, tillsyn, drift och uppförande avverksamheter kopplade till CO2-lagring. Geologin i Sverige lämpar sig dock generellt sett inte förlagring av CO2, förutom för vissa sydliga områden. Nordsjön har en del gynnsamma förutsättningar förCO2-lagring och det finns även potentiella geologiska formationer i södra Östersjön. Sedimentära,basaltiska eller ultramafiska bergarter är att föredra för geologisk CO2-lagring. Den största utmaningenär att hitta rätt sorts berggrund på rätt djup och med rätt volym och porositet. Den största svårigheten med CCS är den höga kostnaden, vilket bidrar till att hämma den utbreddaanvändningen. Kostnaden för CCS inkluderar olika faktorer som infångningsmetod, transportmedel,lagringsplats och övervakning över lagringen. Bland dessa är infångningen den dyraste fasen avtekniken, följt av lagring, transport och övervakning. Kostnaderna för varje fas har analyserats över2olika intervaller med hänsyn till lägre, medelstora och högre kostnader men även beroende på regiondå kostnaden kan variera beroende på ländernas förutsättningar. Infångningsfasen av CCS har betydande kostnadsvariationer beroende på vilken metod som används,renheten hos den infångade CO2 samt den energi som krävs för avskiljningsprocesserna.Högkoncentrerade CO2-strömmar har lägre bearbetningskostnader än lågkoncentrerade. DAC är förnärvarande den dyraste infångningsmetoden. Transportkostnader för CO2 inkluderar kostnaderrelaterade till infrastruktur, drift, underhåll, konstruktion och markanvändning. Kostnaden för transportmed rör beror på faktorer som diameter, avstånd och flödeshastighet. Högre flödeshastigheter genomrörledningar kan minska transportkostnaderna. Lagringskostnader för CO2 omfattar utgifter förborrning, infrastruktur, projektledning, licensiering och platsval. Geologisk lagring på land är förnärvarande mer kostnadseffektivt på grund av de utmaningar och högre kostnader som är förknippademed geologisk lagring till havs. Övervakningskostnader är till exempel screening och utvärdering avlagringsplatser samt uppgifter som datainsamling, platsrankning, brunnsinstallation och seismiskautvärderingar. Att minska energitillgången för infångning, förbättra val av lösningsmedel vid separationsfasen,återanvända och utveckla befintlig infrastruktur är exempel som kan hjälpa till att sänka kostnadernaför CCS-processen och främja en bredare användning. Ett annat förslag för att öka den ekonomiskalönsamheten är genom att implementera CCS nav eller kluster. Dessa CCS nav eller kluster ger företagmöjligheten att samordna infrastrukturen för sina CCS-anläggningar. Detta kan lindra den ekonomiskabördan att bygga upp egen kostsam infrastruktur. Nedlagda olje- och gasfält kan återbrukas för CCS- anläggningar då efterfrågan av fossila bränslenminskar. Istället för att riva ner verksamheterna för fossilt bränsle, exploatera ny mark och borra nyahål kan olje- och gasfälten i exempelvis norra haven återbrukas för CCS- anläggningar. Danmark är ettav de första länderna som har tagit initiativet att omvandla oljeanläggningar till koldioxidlagringanläggningar. Det är möjligt att söka om ekonomiskt stöd från Energimyndigheten eller EU för att få stöd till främstBio-CCS projekt men även andra. Detta är i syfte för att underlätta en fri marknad för tekniker somimplementerar koldioxidinfångst. Ambitionen med detta stödsystem är för att realisera en infångst av10 miljoner CO2 via Bio-CCS och minst 2 miljoner CO2/år för andra CCS tekniker. Genom omvändauktion får det företag som kan erbjuda infångad CO2/ton med Bio-CCS teknik för lägst pris, ta del avstödsystemet. EU har även initiativ att finansiera CCS-projekt genom CETPartnership eller EU:sinnovationsfond vars syfte är att stödja forskning och innovation inom CCS. Sammanfattningsvis kom denna studie fram till att CCS inte är genomförbart idag som en teknik för attminska CO2 från atmosfären med hänsyn till nuläget och kostnaderna för att implementera. Om teknikenenergi effektiviseras och när ekonomiska medel finns på plats är framtiden ljus för CCS. Det är oerhörtrelevant att denna teknik fortsätter att utvecklas till ett bättre, billigare och snabbare sätt att fånga uppCO2 och minska utsläppen av de effektiva växthusgaserna. Regeringen och industrin måste därförsamarbeta bättre för att underlätta regelverk som främjar och möjliggör samarbete inom CCS-branschendå många myndigheter lyfter fram att CCS är en nödvändig teknik för framtiden för att uppnå klimatneutralitet.

An investigation into the commercial feasibility of Carbon Capture and Storage (CCS) technology as a competitive carbon abatement technology for New Zealand.