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(1)AGH UNIVERSITY OF SCIENCE AND TECHNOLOGY. FACULTY OF ENERGY AND FUELS. PhD THESIS. ADVANCED CARBON CAPTURE AND STORAGE TECHNOLOGIES ZAAWANSOWANE TECHNOLOGIE WYCHWYTU I SKŁADOWANIA DITLENKU WĘGLA Agnieszka Ćwik Supervisor: Prof. Ignasi Casanova Dr hab. Katarzyna Zarębska, Prof. AGH Co-supervisor: Dr inż. Paweł Baran AGH University of Science and Technology in Krakow Faculty of Energy and Fuels Department of Coal Chemistry and Environmental Sciences Barcelona, 2019.

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(3) Acknowledgements I would like to express my special appreciation and thanks to my research supervisors Professor Ignasi Casanova, Professor Katarzyna Zarębska and dr. Paweł Baran for their patient guidance, enthusiastic encouragement and useful critiques of this research work. I am particularly grateful for the assistance given by Kwon Rausis who helped me with experimental part of me thesis as well as results interpretation. I am grateful for all the support I received from my family and friends throughout the duration of my PhD studies. A very special gratitude goes to Select +Erasmus Mundus Joint Degree PhD Program for providing the funding for the work. Finally, I would like to give special thanks to InnoEnergy PhD School for giving me the chance to obtain extracurricular education..

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(5) Uprzedzony o odpowiedzialności karnej na podstawie art. 115 ust. 1 i 2 ustawy z dnia 4 lutego 1994 r. o prawie autorskim i prawach pokrewnych (t.j. Dz.U. z 2006 r. Nr 90, poz. 631 z późn. zm.): „ Kto przywłaszcza sobie autorstwo albo wprowadza w błąd co do autorstwa całości lub części cudzego utworu albo artystycznego wykonania, podlega grzywnie, karze ograniczenia wolności albo pozbawienia wolności do lat 3. Tej samej karze podlega, kto rozpowszechnia bez podania nazwiska lub pseudonimu twórcy cudzy utwór w wersji oryginalnej albo w postaci opracowania, artystyczne wykonanie albo publicznie zniekształca taki utwór, artystyczne wykonanie, fonogram, wideogram lub nadanie.”, a także uprzedzony o odpowiedzialności dyscyplinarnej na podstawie art. 211 ust. 1 ustawy z dnia 27 lipca 2005 r. Prawo o szkolnictwie wyższym (t.j. Dz. U. z 2012 r. poz. 572, z późn. zm.) „Za naruszenie przepisów obowiązujących w uczelni oraz za czyny uchybiające godności studenta student ponosi odpowiedzialność dyscyplinarną przed komisją dyscyplinarną albo przed sądem koleżeńskim samorządu studenckiego, zwanym dalej "sądem koleżeńskim"”, oświadczam, że niniejszą pracę dyplomową wykonałem(-am) osobiście i samodzielnie i że nie korzystałem(-am) ze źródeł innych niż wymienione w pracy.. ……………………………………………………. podpis autora pracy.

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(7) Table of Contents Introduction.................................................................................................................................................... 11 Aim of PhD thesis .................................................................................................................................................. 12 Chapter 1. Carbon Capture Technologies ...................................................................................................... 13 1.1. CO2 Capture Technologies ....................................................................................................................... 15. 1.2 Pre-combustion CO2 capture process ............................................................................................................... 15 1.3 Post-combustion CO2 capture processes .......................................................................................................... 17 1.4 Oxy-fuel combustion technology ..................................................................................................................... 22 Chapter 2. CO2 Storage in underground reservoirs ........................................................................................ 25 2.1 Geological storage of CO2 in depleted oil and natural gas fields or those undergoing depletion .................... 28 2.2 Geological storage of CO2 in deep saline aquifers ........................................................................................... 30 2.3 Storage in unmineable coal seams ................................................................................................................... 32 Chapter 3. Mineral carbonation ..................................................................................................................... 37 3.1 Ex-situ mineral carbonation ............................................................................................................................. 40 3.2 In-situ mineral carbonation .............................................................................................................................. 48 3.3 Carbonation of industrial residues ................................................................................................................... 51 Chapter 4 – CO2 Storage in coal .................................................................................................................... 53 4.1 Sorption of methane and carbon dioxide in isothermal and non-isothermal conditions .................................. 53 4.1.1 Test material ................................................................................................................................................. 53 4.1.2 Experimental ................................................................................................................................................. 54 4.1.3 Test procedure............................................................................................................................................... 55 4.1.4 Results and discussion .................................................................................................................................. 56 4.2 Modelling of reactions ..................................................................................................................................... 62 4.3 Conclusions...................................................................................................................................................... 65 Chapter 5. CO2 utilization in fly ash .............................................................................................................. 67 5.1 Fly ash and its use in construction industry ..................................................................................................... 67 5.2 Use of fly ash for mineral carbonation process ................................................................................................ 71 5.3 Selection of different type of fly ash materials ................................................................................................ 72 5.3.1 Belchatow ..................................................................................................................................................... 72 5.3.2 Biomass fly ash ............................................................................................................................................. 76 5.3.3 Andorra ......................................................................................................................................................... 79 5.3.4 La Pereda ...................................................................................................................................................... 80 5.3.5 Ptolemais....................................................................................................................................................... 83 5.3.6 Megalopolis .................................................................................................................................................. 85 Chapter 6. Feasibility study of fly ash carbonation ....................................................................................... 89 6.1 Carbonation of Belchatow fly ash .................................................................................................................... 89 6.1.1 Methodology ................................................................................................................................................. 89 6.1.2 Procedure ...................................................................................................................................................... 91 6.1.3 Results and discussion .................................................................................................................................. 92 6.1.4 Conclusions................................................................................................................................................... 94 7.

(8) 6.2 Pre-eliminary studies – Biomass fly ash .......................................................................................................... 95 6.2.1 Methodology ................................................................................................................................................. 95 6.2.2 Procedure ...................................................................................................................................................... 95 6.2.3 Results and discussion .................................................................................................................................. 95 6.2.4 Conclusions................................................................................................................................................. 100 Chapter 7. Mineral carbonation of high – calcium Ptolemais fly ash .......................................................... 101 7.1 Description of apparatus ................................................................................................................................ 101 7.2 Characterization techniques ........................................................................................................................... 103 7.2.1 X-ray Fluorescence analysis ....................................................................................................................... 103 7.2.2 X-ray diffraction analysis ........................................................................................................................... 103 7.2.3 Thermogravimetric analysis ........................................................................................................................ 104 7.2.4 Scaning Electron Microscopy ..................................................................................................................... 104 7.2.5 Infrared Spectroscopy ................................................................................................................................. 104 7.3 Dry conditions - effect of temperature on carbonation .................................................................................. 104 7.4 Dry conditions - effect of pressure on carbonation ........................................................................................ 111 7.5 Effect of water vapor addition on carbonation ............................................................................................... 111 7.6 Carbonation efficiency ................................................................................................................................... 112 7.7 FITR analysis ................................................................................................................................................. 114 7.8 Microstructural analysis ................................................................................................................................. 117 7.9 Conclusions.................................................................................................................................................... 119 Chapter 8. Comparative study of high – calcium fly ash carbonation from Poland, Spain and Greece ....... 121 8.1 Methods ......................................................................................................................................................... 121 8.2 Continuous pressure flow conditions ............................................................................................................. 123 8.3 Batch reactor conditions ................................................................................................................................ 127 8.4 Thermogravimetral analysis........................................................................................................................... 128 8.5 Carbonation efficiency and CO2 sequestration capacity ................................................................................ 130 8.6 Microstructural analysis ................................................................................................................................. 132 8.7 Conclusions.................................................................................................................................................... 134 Chapter 9. Carbonation of fly ash with simulated flue gas .......................................................................... 137 9.1 Methods ......................................................................................................................................................... 137 9.2 Analysis of material before and after treatment ............................................................................................. 137 9.3 Carbonation Efficiency .................................................................................................................................. 141 9.4 Case – study for Ptolemais Power Plant ........................................................................................................ 141 9.5 Conclusions.................................................................................................................................................... 142 Chapter 10. Free lime determination studies................................................................................................ 143 10.1 Methods ....................................................................................................................................................... 143 10.2 Results.......................................................................................................................................................... 143 10.3 Conclusions.................................................................................................................................................. 145 General Conclusions .................................................................................................................................... 147 Future work .......................................................................................................................................................... 151 8.

(9) Achievements of the author ......................................................................................................................... 153 References.................................................................................................................................................... 157 Summary ...................................................................................................................................................... 171 Streszczenie ................................................................................................................................................. 173 Resumen ...................................................................................................................................................... 175 List of Figures .............................................................................................................................................. 177 List of Tables ............................................................................................................................................... 181. 9.

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(11) Introduction CO2, which is the main component among the greenhouse gases is the reason for the global warming, direct cause of the climate change. In recent century human action added to the increasing carbon dioxide emissions by constantly growing industrialization and burning big amounts of fossil fuels. Without taking any actions regarding lowering the current levels of the CO2 emissions, the global temperatures will continue to rise and the effects of this scenario will bring disastrous consequences. Earth’s fauna and flora, together with the human race can be endangered. In order to decrease the global carbon dioxide emissions, three main actions have been taken: improvement the energy efficiency, increase the use of non-polluting sources of energy and introduction of the Carbon Capture, Sequestration and Utilization Techniques (CCSU). These approaches need to be taken in order to meet the objective of the Paris Agreement made by the United Nations, which is keep the global temperature rise this century under 2 degrees Celsius above pre-industrial levels. Current CCUS research focus is set mainly on CO2 storage technologies, with a special emphasis on the assessment of geological reservoirs as traps for CO2 injected. Reactive technologies like mineral carbonation have not been yet fully explored, probably due to the scarcity of relevant experimental data and complexity of the mineral systems involved. In this work the research is focused on the study of sorption of carbon dioxide and methane on coal samples, and their implications on swelling by maintaining the processes at different conditions. Modelling of methane and carbon dioxide sorption and sorption – induced coal expansion has also been done in order to have better understanding of the process. Second part of the work is concerned on the carbon dioxide utilization processes in waste materials. It was identified that high – calcium fly ashes are the potential substrate for the mineral carbonation. In this process CO2 is transformed into stable chemical form called carbonate. With the very low utilization rate of high – calcium fly ashes, it was decided to do the feasibility study of this type of fly ash carbonation. Preliminary results of the fly ash carbonation gave the reason to extend the research on different types of fly ashes, produced in Europe. Selection of different types of waste material was chosen and comparative study of potential for carbonation of them was tested. Complementary to this, optimization of the carbonation process was done in order to discover the influence of the temperature, pressure, time, addition of water vapor and using different type of pressure system on the reaction. To find the best conditions for the process, sequestration capacity and process efficiency was calculated. Complementary to the CO2 utilization through fly ash carbonation, additional aim of this research was to determine the free lime decrease in the fly ash after carbonation. Lowering the free lime. 11.

(12) content in high – calcium fly ash could potentially increase the use of this type of waste in construction materials.. Aim of PhD thesis. The aims of this PhD thesis are as follows: -. Study of the methane and carbon dioxide sorption at different temperature conditions. -. Optimization of the carbonation process conditions in order to achieve the best carbonation efficiency. -. Comparative study of different fly ashes potential to carbonation. -. Comparison of the carbonation of fly ash with simulated flue gas and pure CO2 stream. -. Lowering the free lime content in high – calcium fly ash by carbonation reaction. Objectives of this thesis are as follows: -. High – calcium fly ash is a good substrate for carbonation and for CO2 utilization. -. Acceleration of carbonation can be done by increasing temperature, pressure or addition of water vapor. -. Carbonation of high- calcium fly ashes leads to lowering the free lime content. 12.

(13) Chapter 1. Carbon Capture Technologies The Earth’s climate has change multiply times through the history. There has been seven cycles of glacial advance and retreat, with the last end of the ice age 7000 years ago. After that the modern climate era started as well as the human civilization. Observed current warming trend has almost 100% probability of being caused by human activity, starting from the 20th century and proceeding at high rate. Data collected from the earth-orbiting satellites and other technological appliances are the strong evidence of changing climate [1]. The heat-trapping property of carbon dioxide and other gases was already exposed in the mid-19th century. Greenhouse gases have ability to transfer infrared energy through the atmosphere and in effect, warming the Earth. There will be a lots of effect caused by the Climate Change: temperature rise, change in growing seasons and precipitation patterns, increased probability of droughts, heat waves and hurricanes, rise of sea levels. Global warming is the biggest environmental issue for current human generation [2]. To take action upon this phenomenon, UNFCCC – United Nations Framework Convention on Climate Change signed the Paris Agreement in 2015, agreeing to take actions to keep a global temperature rise below 2 Celsius degrees. In order to achieve that, worldwide carbon dioxide emissions have to be lowered. Lot of different actions are being implemented. Three main approaches introduced are: using non-polluting sources of energy, increasing the energy efficiency and expansion of Carbon Capture, Sequestration and Utilization techniques. Carbon Capture, Sequestration and Utilization (CCSU) defines all the techniques for capturing, storing or/and utilizing carbon dioxide which would be emitted or remained in the atmosphere without using them [3]. Those techniques are usually applied at places with significant carbon emissions: fossil fuel power stations, cement manufacturing, ammonia production, iron and non-ferrous metal production, industrial boilers and refineries. The general idea standing behind applying CCSU is to be able to still use fossil fuels while reducing the CO2 emissions into the atmosphere. World Energy Outlook [4] shows that energy from fossil fuels will be present in the World Energy Consumption mix in 2040, as it can be seen in Figure 1. Global demand for energy is expected to increase by 25% by 2040. It is led by constantly growing human population, increasing electrification and expansion of the economies, especially in the Asia Pacific Region [5]. In the future there will be a need to undertake all energy sources to satisfy demand growth. Oil and natural gas are expected to reach 60% of the global supplies, while nuclear and renewables will grow for about 50% and become 35% of the energy mix.. 13.

(14) a). b) Figure 1. World Energy Consumption in 2013 (a) and predicted for 2040 (b) by fuel source (International Energy Outlook, 2017).. According to the International Energy Outlook, energy related emissions will increase from 33.9 billion metric tons in 2015 to 36.4 billion metric tons in 2030, and further to 39.3 bln metric tons in 2040. This growth will be caused by the economic development in non-OECD as the emissions in OECD countries will remain stable. The main sources of the carbon dioxide emissions are: industrial processes, power generation, energy transformation, transport, residential and services [6]. Considering that the polluting energy sources are expected to be constantly use, CCSU is the only option to achieve provisions from 14.

(15) the 2015 Paris Agreement. Carbon Capture and Sequestration technologies can be generally divided to capturing and compressing CO2, transporting it and either storing in underground deposits or utilizing.. 1.1 CO2 Capture Technologies There are three main CO2 capture technologies developed: pre-combustion, post-combustion and oxy-fuel combustion [7] that can be installed at power plants where energy from fossil fuels is generated.. 1.2 Pre-combustion CO2 capture process. Pre-combustion system is applicable to gasification combined cycle power plants (IGCC). In precombustion method a special air-separation system is installed which produces stream of a pure oxygen. This gas is further injected to the gasifier where reacts with pulverized coal and synthetic gas ‘syngas’ (CO + H2) is being created. Next, steam is added to it in a water shift reactor and converts carbon monoxide into carbon dioxide. CO2 is captured from this stream by physical wash and after compression is ready for either storage or utilization. Hydrogen is used as a fuel for turbines power and electricity. Recovered heat is used for steam production that also drives a turbine generator for electricity. The carbon dioxide is captured from the syngas before it is combusted in the gas turbine [8]. The scheme of this technology is presented in Figure 2 [9]. This process is in principle the same for coal, oil or natural gas. However, when using coal or oil, more stages of gas purification must be made to remove ash, sulfur or other impurities. Installing a precombustion CO2 capture system in gas fired combined power plant causes 16%-point efficiency loss as recent studies shows [9]. The major efficiency losses are prompted by: syngas production (6%-points), the WGS section (3%-points), the H2/CO2 separation section (5%-points) and CO2 compression and drying section (2%-points). Research and development concerning pre-combustion technology involves efficiency improvements in all of the stages of it: syngas and oxygen production, Water Gas Shift reaction, H2/CO2 separation, CO2 compression and power production with hydrogen used as a fuel [10].. 15.

(16) Figure 2. Integrated gasification combined cycle power plant diagram (U.S. Department of Energy).. This technology has advantage of producing carbon-free fuel (H2) and carbon dioxide at elevated pressure (CO2/H2 concentration at the inlet is between 2 and 7 MPa), thus reducing the power consumption needed for the gas compressing needed for transportation and storage of CO2. One of the challenges in this capture technique is the adsorption process during which syngas is scrubbed with a liquid solvent in order to selectively remove acid components (i.e. CO2 or H2S). Absorption process is carried in a column fitted with trays or structured packing. The acid components are discharged upon regeneration after which the solvent is re-circulated to the absorber. Gas components can be either attached physically or bound chemically to the solvent, thus absorption processes are characterized as either physical or chemical. Sometimes mixing of physical and chemical solvent is used, exploiting beneficial characteristics of both solvents. The capacity of the chemical solvents is determined by the amine amount in the solution. Regeneration in chemical absorption is done by addition of heat at low pressure through the reboiler of the stripper column. Chemical solvents are generally used for CO2 removal from gas stream at low CO2 partial pressure because they have high affinity for carbon dioxide. Energy requirements for this type of solvents regeneration are rather high. In case of physical solvents, their loading capacity depends on Henry’s law, what results in a linear dependency between the partial pressure of the removed component and the solvent loading [11].. 16.

(17) Figure 3. Comparison between chemical and physical solvents for pre-combustion process (Global CCS Institute).. As there is dependency between partial pressure and solvent regeneration, pressure reduction can be used for the solvent recovery. Physical solvents are typically used to remove CO2 and H2S from raw gases made from oil and coal gasification. Physical solvents for pre-combustion capture are temperature and pressure dependent, i.e. high partial pressures of CO2 and low temperatures accelerates the absorption. High CO2 partial pressures at the absorber allows physical absorption to be suitable for CO2 capture in an IGCC system. After gas separation, CO2 is being compressed. In spite of being separated at moderately high pressures, at the end CO2 is available as pure gas at about ambient pressure. Primary, the CO2 stream is compressed near the critical pressure; the compression energy consumption is optimized by using multiple intercooled stages. Next, carbon dioxide is cooled to achieve the liquid phase. Lastly, liquefied CO2 is pumped to the delivery pressure (110 - 150 bar, according to transport specifications). Depending on the separation technology used, CO2 stream could contain traces of N2, H2, and CH4. Therefore, to achieve higher purity level for storage or utilization, additional purification process should be employed [12– 14]. The cost of 1 tone of CO2 capture using pre-combustion technology is 24 – 41 U.S. dollars at IGCC power plants and 42-87 U.S. dollars at IGCC power plants based on supercritical pulverized coal [15].. 1.3 Post-combustion CO2 capture processes. Units installed after fuel combustion to capture CO2 have a common name as post-combustion capture systems. Usually they are installed after traditional purification structures for reducing contaminants like NOx, SOx and other small particles. There are many different post-combustion capture 17.

(18) technologies which are being developed since many years: chemical absorption [16], adsorption [17], membrane separation [12,18], Ca-looping technology [19–21] and cryogenic fractionation [22]. These methods are presented in Figure 4 [23]. Some of them are still not commercially used for CO2 capture in industrial processes [24]. One of the reasons limiting implementing this type of technologies at coal power plants is low CO2 partial pressure in the flue gas. Usually, the flue gas is under atmospheric pressure with only 12-15% concentration of carbon dioxide, so it is problematic to separate it from the flue gas. In 2015, Rubin et al. [15] calculated cost of capturing of 1 tone of CO2 between 36 – 53 U.S. dollars at traditional power plants with pulverized coal-fired boiler and 48 – 111 U.S. dollars at Natural Gas Combined Cycle (NGCC) power plants.. Figure 4. Post-combustion capture technologies (M. Wang, 2011).. Chemical absorption Among the technologies listed, chemical absorption is so far the most economical and possible to be implemented in industry. As a solvent, typically monoethanoamine (MEA) is used.. 18.

(19) Figure 5. Chemical absorption technology for CO2 capture (A. Lawal, 2010).. Chemical absorption technology scheme is presented in Figure 5 [25]. The flue gas passes the absorber from the bottom upwards as the solvent solution flows downwards, creating a counter flow. During the contact of these two streams, some of CO2 from the flue gas is absorbed into amine solution. After that, rich-loading solution with CO2 is pumped up to the head of the stripper. In the stripper, there is also a counter flow appearing when CO2 solution flows down the column and strips steam generated in the reboiler. Heat from stripping steam breaks chemical bonds between CO2 and the solvent and CO2 is carried up by the ascending steam to overhead condenser. When the condensed steam is directed back to the stripper as a reflux, the product stream with high CO2 purity (around 99%) is collected. After that, clean amine solution is circulated back to the absorber. CO2 can be compressed for storage afterwards [26]. In this technology, solvent regeneration in the reboiler is responsible for the highest energy consumption. For a 600MW coal-fired power plant, the regeneration of MEA in the chemical absorption process needs 3.8-4.0 GJ/tons CO2. There are 3 aspects of this process that are being optimized in order to reduce the energy consumption: operational parameters, process modifications and solvents development.. Adsorption. Adsorption on solid sorbents has several advantages when compare to liquid-based absorption. From an engineering perspective, using solid sorbents eliminates creation of liquid waste streams. Disposal routes for benign solids waste are simpler and there is broad range of compatible operating temperatures [27]. Moreover, solid adsorbents are not volatile and by using them large energy penalties associated with the regeneration of liquid absorbents are avoided due to water evaporation in the stripper. From a materials context, solid sorbents have higher cyclic CO2 capacities per unit weight than liquid absorbents and can be easier regenerated. Figure 6 presents simplified scheme of the solid sorbet CO2 19.

(20) capture [28]. There are two types of adsorption technologies: fixed or moving. In fixed bed adsorption usually pelletized or structured sorbents are used in form of packed beds. Packed beds can have configurations as single vessels or moving/rotating vessels arrangements. One of the examples of the moving adsorption systems are fluidized beds. The adsorber size is chosen depending on the cycle time (CO2 uptake per cycle or per unit volume of material) and needed CO2 uptake. Cyclic capacity depends on the sorbent material and adsorber design. Main challenges for selecting solid sorbents for this process are: sintering, attrition and chemical deactivation [29]. Costs related to adsorption are associated with the regeneration process and energy penalties caused by modifications of the system by addition of the capture system. Thus, adsorber system should not require significant modification of the sorbent material and its application to the existing apparatus should be easy. Temperature swing adsorption (TGA) is another interesting approach in sorption technologies as it can use the waste heat from the process itself, for example waste heat sources can be found in cement and iron/steel processes [27]. Usually pressure swing adsorption (PSA) is preferred as much faster than TSA. TSA has to be combined with vacuum swing adsorption (VSA) in order not to pressurize the flue gas prior to adsorption. Alternative method to the TSA is rapid temperature swing adsorption (RTSA). In this technology use of hollow fibre adsorbents containing an impermeable core incorporating cooling or heating mediums for efficient adsorption and faster regeneration.. Figure 6. Scheme of solid sorbent CO2 capture (J.W. Dijkstra, 2017).. 20.

(21) Membrane separation. Figure 7 illustrates process for flue gas membrane separation technology [30]. Process starts with cooling the flue gas in wet scrubber to achieve suitable temperature for the membrane entering. Next, a portion of carbon dioxide pass through the membrane and a stream (permeate gas) with higher CO2 concentration is received on the other side. The residue part of the flue gas is called retentate gas. As mentioned before, the partial pressure of CO2 is very low and compressor + vacuum pump is used to increase the partial pressure difference between the two different sides of membrane.. Figure 7. Membrane separation technology (R. Anantharaman, 2014).. Compared to chemical absorption process, the membrane separation process seems to be simpler since it has less components. The major energy consumption is generated by compressor and vacuum pump [31]. There are two properties of the membrane material that affects the selectivity degree and CO 2 concentration in permeate gas: permeability and selectivity. Materials used for the membrane are either inorganic (ceramic), organic (polymeric) or hybrid. Although this separation method has a big potential to be a low energy and low-cost solution for CO2 capture, its application is still limited by some practical problems: energy consumption by the compressor and pump, membrane large volume and cost.. Calcium Looping Technology Calcium Looping Technology is a low cost 2nd generation capture technology developed in recent years [32]. In this process CaO is used as a recoverable sorbent for carbonation/calcination cycles as presented in Fig. 7 [33]. Therefore, CO2 present in the flue gas stream (15% concentration) is captured by partial carbonation of the calcium oxide particles in a fluidized bed reactor (carbonator) at 650⁰C under atmospheric pressure. This temperature secures a low value of the equilibrium CO2 concentration (~1% vol.) and fast enough reaction kinetics for carbonation to take place in short reaction time, achieving reduction of the CO2 concentration in the gas exiting the carbonator [34]. Calcium carbonate 21.

(22) particles flows into a second reactor (calciner) where calcination is held to regenerate the sorbent at temperatures above 930⁰C under a CO2 environment with 70% and 90% concentration. The CO2 gas exiting the calciner is thus ready for the next stages of processing or transport. Calcium looping technology is already validated in pilot-scale coal fired plant of 1–2 MWth [33,35].. Figure 8. Calcium Looping Technology (A. Perejon, 2016).. Limestone (CaCO3) is used to produce CaO by precalcination (prior the capture). During this process some amounts of carbon dioxide are produced. High consumption of the fuel and oxygen for this method creates energy penalty to the technology. It is calculated that the heat consumption for this process imposes net efficiency penalty of 5-8 points, which is a lower value when compare to the penalties imposed by other capture methods [36]. It is discovered that improving the multicyclic activity of sorbent would considerably improve the energetic efficiency of the process [37].. 1.4 Oxy-fuel combustion technology. The concept underlying behind the oxy-fuel capture technology is to extract the nitrogen from the combustion air prior to the combustion by air-separation unit. The simplified model of this technology is presented in Figure 8 [38].. 22.

(23) Figure 9. Simplified model of oxyfuel capture unit (V.White, 2013).. To capture carbon dioxide, exhaust gas with high concentration level of CO2 and water vapor is generated followed by separation of CO2 from the flue gas through dehydration and low temperature purification processes. Oxy-fuel combustion for power generation mainly consists of the consecutive units: • Air Separation Unit (ASU) – for oxygen production; • Boiler / Gas Turbine – combustion of fuel & heat generation; • Flue Gas Processing Unit – flue gas cleaning or control system for gas quality (GQCS); • CO2 Processing Unit (CPU) – final purification of the CO2 in order to prepare it for transport and storage [39]. Removing nitrogen from the oxidant leads to creation of stream of highly concentrated CO 2 after the combustion process. Usually, recycled flue gases are used to substitute nitrogen and regulate the combustion temperature. The idea of applying oxyfuel technology with flue gas recycle in fossil-fueled plants to control the emissions and produce high concentration CO2 streams for enhanced oil recovery (EOR) was first recommended in 1982 [40]. Therefore, the leading goal of this technology application in coal-fired plants is not to achieve high temperatures, but to recover carbon dioxide in an air-like combustion environment. In existing power plants equipped by the conventional air combustion system the combustion temperature and heat transfer rate are purposely maintained in order to use the existing equipment. In oxy-fuel technology the operating conditions are similar to an air-combustion environment without creating any economic and safety concerns. Because of this reasons this system is 23.

(24) seen not only as an adequate technology for new plants but also as a retrofit strategy for existing units [41]. The cost of capturing of 1 tone of CO2 with ox-fuel combustion technology is equal to 36-67 U.S. dollars [15].. 24.

(25) Chapter 2. CO2 Storage in underground reservoirs Geological carbon storage (GCS) is a promising technology for mitigation of increasing CO2 concentrations in the atmosphere. Injection of the carbon dioxide into permeable subsurface formations is the only storage technology that already has been deployed and demonstrated on a commercial scale [42]. Ongoing projects concerning the carbon dioxide storage are presented in Figure 10 and Table 1 [43].. Figure 10. CO2 Storage projects worldwide (Helmholtz Zentrum Potsdam, 2017).. To be suitable for the carbon dioxide storage, geologic formation must meet following conditions: -. Have depth of more than 800 m to keep the gas in supercritical state,. -. Have a large storage volume,. -. Be covered by a seal rock to prevent vertical flow of the gas,. -. Be leak-free,. -. Be permeable in order to allow CO2 injection at reasonable rates [44].. The injection of supercritical CO2 into geological formations disrubs the physical and chemical state of the subsurface. The reservoir rock and overlying caprock can be exposed to following changes: pore fluid pressure, thermal state, chemical reactivity and stress distribution. These changes can lead to mechanical deformation of the rock mass, affecting existing fractures or initiation of new ones, which finally can peturb the unity of the overall geological carbon storage system over years, crucial for successful carbon dioxide storage [45]. GCS sites are practically unified systems. However, they can be 25.

(26) divided by the physics and spatial scales over scientific investigations. For most applications, decoupling the physics by handling the surrounding system as a boundary condition works properly. The coupling processes merge different combinations of thermal, hydrological, chemical, mechanical, and biological effects. Coupled processes are time and length-scale dependent. There is an indisputable necessity for understanding the processes coupling during GCS. Table 1. Large CCS Projects worldwide (A. A. Olajire, 2013). Project. Location. Capture process. Storage. Year. Rangely Weber. USA. Gas processing. EOR with MMV. 1986. Sand Unit CO2. (measurements,. injection project. monitoring and verification). Sleipner CO2. Norway. Gas processing. injection. Deep saline. 1996. formation. Weyburn-Midale. Canada/USA. Pre. EOR with MMV. 2000. Enid Fertilizer. USA. Pre. EOR. 2003. Salt Creek EOR. USA. Gas processing. EOR. 2004. In Salah CO2. Algeria. Gas processing. Deep saline. 2005. injection Snohvit CO2. formation Norway. Gas processing. injection Appalachian Basin. 2006. formation USA. Gas processing. R.E. Burger Plant Michigan Basin. Deep saline. Deep saline. 2008. formation USA. Gas processing. State-Charlton. Deep saline. 2008. formation. Schwarze Pumpe. Germany. Oxy. Depleted gas. 2008. ECO2 Berger. USA. Post. Vented. 2008. Pleasant Prairie. USA. Post. Vented. 2008. Cincinnati Arch. USA. Gas processing. Deep saline. 2009. East Bend Station. formation. AEP Mountaineer. USA. Post. Saline. 2009. Shidongkou. China. Post. Commercial uses. 2009. Lacq. France. Oxy. Depleted gas. 2010. Puertollano. Spain. Pre. Recycled. 2010. Brindisi. Italy. Post. EOR. 2011. Buggenum. Netherlands. Pre. Vented. 2011. Callide-A Oxy Fuel. Australia. Oxy. Saline. 2011. 26.

(27) Plant Barry Project. USA. Post. Deep saline. 2011. formation Ordos project. China. Post. Deep saline. 2011. formation Mongstad. Norway. Post. Saline. 2012. Ferrybridge. UK. Post. Depleted oil. 2012. Carson-DF2. USA. Post. EOR. 2012. Big Bend Station. USA. Post. Vented. 2013. Polk. USA. Post. Saline. 2013. TCEP. USA. Pre. EOR. 2014. Trailblazer. USA. Post. EOR. 2014. Kemper County. USA. Pre. EOR. 2014. HECA. USA. Pre. EOR. 2014. Belchatow. Poland. Post. Saline. 2014. Karlshamn. Sweden. Post. Vented. 2014. FutureGen. USA. Oxy. Saline. 2015. Daqing. China. Oxy. EOR. 2015. Road. Netherlands. Post. Saline. 2015. Compostilla. Spain. Oxy. Saline. 2015. Gorgon CO2. Australia. Gas processing. Deep saline. 2015. injection. formation. BP Peterhead-DF1. UK. Post. Depleted gas. 2015. Don Valley Power. UK. Post. EOR. 2015. UK. Pre. Depleted oil. 2016. Kilingholme. UK. Pre. Saline. 2016. White Rose. UK. Oxy. Saline. 2016. WA Parish. USA. Post. EOR. 2017. Bow City. Canada. Post. EOR. 2017. Project Teeside Low Carbon. During injection, CO2 is transferred to the geological reservoir at depths between 800 and 5000 meters, where the pressure is higher than 74 bars. Thus, the CO2 is in a supercritical state. At depth of 800m, 1 ton of carbon dioxide occupies 1-2 m3, allowing to store significant amounts of the gas in relatively small space [44]. Geological reservoirs are composed of porous rocks: sandstones and carbonates with pores that can be filled with CO2. A thick and impermeable caprock which is fine-grained or rock salt, is placed. 27.

(28) on top of the reservoir and disable any CO2 from escaping to the surface. This caprock is important for maintaining a closed reservoir and for preserving the injected CO2 at a proper depth. Different sources present different cost estimation of the CO2 storage in geologic formations. Typical ranges of onshore storage cost on a common basis are between 1 – 18 U.S. $/tCO2 [15]. There are different types of geological reservoirs for the carbon dioxide storage, as presented in Figure 11.. Figure 11. Different types of reservoirs for the geological storage of CO 2 (GRREBS, 2018).. 2.1 Geological storage of CO2 in depleted oil and natural gas fields or those undergoing depletion. One of the options to store captured CO2 is to inject the gas into oil fields and in the same time enhance the production of oil from the fields. This option, called CO2 Enhanced Oil Recovery (CO2EOR), is an economic approach to achieve a low-carbon future. Revenues from CO2 sales to the EOR industry can partially offset the costs of CO2 capture. This technology is commercially deployed in U.S. and Canada since many years. Some of the projects were not developed with the CO2 storage as one of 28.

(29) the objectives. CO2-EOR is not a new invention – commercial and profitable systems are existing since 30 years in suitable oil fields combined with easy access to carbon dioxide [45]. In 2018, more than 100 CO2 – EOR projects in U.S. gave 250 000 barrels per day of incremental oil. To achieve that, extensive pipeline system has been developed to transfer the carbon dioxide needed for oil recovery.. Figure 12. Enhanced Oil Recovery technology (Clean Air Task Force, 2018). Suitable oil fields where this technology could be deployed need to meet the technical criteria for achieving miscibility and have sufficient unrecovered oil amount. CO2-EOR technology has extensive potential to store significant amount of carbon dioxide: 54 largest oil basins in the world could produce 470 to 1,070 barrels of oil and store 140 – 320 billion metric tons of CO2 [46]. Reported mechanism of CO2-EOR is as follows [47]: -. Oil viscosity reduction. -. Oil swelling due to CO2 dissolution in crude oil. -. Removal of near well damages. -. Solution gas drive caused by gravity drainage. -. Improved drainage of reduced viscosity oil by encroaching water. -. Vaporization of lighter oil components by CO2. -. Reduction of water permeability. -. Reduction of interfacial tensions. In U.S. roughly half of the potential CO2 demand for ongoing CO2-EOR projects can be satisfied by large, anthropogenic CO2 sources within distances comparable to existing and planned CO2 pipelines serving EOR projects (800 km). 29.

(30) Many techno-economical models were developed in order to estimate the cost of the CO2-EOR systems. Estimating storage capacity in hydrocarbon reservoirs is simple since the reservoir intervals are well described and capacity estimation is done by the replacement principle in which the equivalent volume of oil and/or gas can be used for CO2 storage. Torleif et al. studied the economic potential of this technology in the North Sea [48]. 18 Norwegian and 30 UK oil fields were considered, with 40 years of project lifetime and CO2 deposition of constant rate of 178 million tones/year. The potential for additional incremental oil production was estimated between 658 and 696 million m3. Price of CO2 was calculated between 23-94 USD/tone and oil as 20-150 US/bbl. When the oil prices reach 90-100 USD/bbl than the CO2 price is close to the CO2 capture – 50 USD per ton [48].. 2.2 Geological storage of CO2 in deep saline aquifers. In contrary with the estimation of CO2 storage capacity in oil and gas reservoirs, calculations for storage in saline aquifers are much more problematic. The concepts are either based on considering the whole aquifer or structural and stratigraphic traps. Also, carbon dioxide can be considered either as a free phase or in solution. CO2 can be physically trapped (in structural and stratigraphic traps, at irreducible saturation in the pore space) or chemically trapped (in form of solution or transforming into mineral), or both simultaneously [49]. Another difficulty in order to estimate the storage potential in saline aquifers is that different CO2 bonding processes occurs over different period of times [50]. For the evaluation goal the time of CO2 injection is important as well as the time of CO2 free phase immobilization, when this phase no longer migrates and final extent of CO2 plume can be defined (Fig.13). When CO2 is injected in a structural or stratigraphic trap or in a closed aquifer, then the time of immobilization and cessation of injection is the same. If carbon dioxide injection happens in open aquifer, then the time of immobilization occurs after the cessation of injection. Therefore, a closed aquifer is determined as an aquifer where CO2 reaches aquifer’s boundaries before injection ends, whilst in an open aquifer gas migrates due to buoyancy and reaching aquifer’s boundaries takes longer time.. 30.

(31) Figure 13. The scheme of CO2 storage in saline aquifers (Gan, 2017).. As it can be seen in Figure 13, mineral trapping occurs over times longer than 10 years and because of that reason it doesn’t contribute to the storage capacity during the gas injection and it is not considered for the capacity estimation. Carbon dioxide which dissolves in the aquifer water lowers its density for 1% and sinks to the bottom of aquifer due to the gravitation and consecutive missing [51].. Figure 14. Main trapping mechanisms for saline aquifer storage of CO2 (P. Ringrose, 2018).. In situ factors influencing the CO2 solubility are pressure, temperature and salinity. Usually both, mineral trapping and solubility in water is omitted when estimating the storage capacity. The effective storage capacity is based on approach of storage efficiency where not all the pore space is available and saturated with CO2. Presently, the storage efficiency as well as efficiency coefficients has been 31.

(32) calculated for the gas storage in free- phase in deep saline aquifers. This are the basics of the TechnoEconomic Resource-Reserve pyramid presented by Bachu et al. [52]. Characteristics of the storage aquifer: -. In situ conditions: pressure, temperature and salinity. These parameters directly affect the density and viscosity of the fluids inside the reservoir,. -. Displacement characteristics of the CO2/brine system, among other irreducible saturations and relative permeability of CO2 and water,. -. Internal characteristics: lithology, environment of deposition, porosity and permeability distributions, heterogeneity, compressibility,. -. External characteristics: areal extent, thickness, slope and topography of the aquifer top, local structural straps and boundaries.. Two commercial ongoing projects where CO2 is stored in saline aquifers, are Sleipner, started in 1996 and Snøhvit started in 2008, both located in offshore territory of Norway [53]. 22 Mt of CO2 has been stored in those projects together. In Sleipner CO2 is injected and stored in the Utsira formation at a depth of 800-1000 m below the sea level. One shallow long-reach well is used for the gas injection 2.4 km from the production platform. The CO2 plume monitoring observations at Sleipner reveal an overall storage efficiency equal to 5% (after 14 years of injection). Nearly one tenth of this volume dissolved in the brine phase. Second project is part of the Snøhvit gas field development in the Barents Sea. Carbon dioxide is extracted from the gas at the onshore gas processing plant (Melkøya) and transported through a 150 km long pipeline to a subsea injection place.. 2.3 Storage in unmineable coal seams. Carbon dioxide can be effectively stored in the unmineable coal seams, which cannot be mined for energy purposes. Since any action towards coal, like mining, combustion or gasification would release the gas stored in the seam, only unmineable coal is seen as suitable for the CO2 storage [54]. There are lot of factors affecting coal minability. The reservoir cannot be mined if it is either too deep, thin, small or of poor quality. Also, there could be some land restrictions or mining has low economic feasibility. Coal is defined as unmineable if its placed deeper than 350 meters of overburden according to the Department of Energy (DOE). Midwest Geological Sequestration consortium defines all coals placed shallower than 152 m as mineable and those placed at depth 152 – 305 m as unmineable. As the mining technologies are constantly being innovated, the definition of mineable coals constantly changes and it is problematic to quantify the possible CO2 storage in coal. Practical thinking lead to the estimation of the potential CO2 storage in coal in current times, but with keeping in mind that part of the coal can eventually be mined and potential will be smaller. Department of Energy Regional Carbon Sequestration 32.

(33) Partnership calculated that between 60 and 117 billion metric tons of CO2 can be stored in coal, but other sources value the storage to even up to 200 billion metric tons of CO2. The processes responsible for the CO2 storage in coal are adsorption and diffusion [54]. Diffusion take place when the CO2 molecules move through large (greater than 30 nm) pores, fractures, and cleats. Sorption of the gas occurs by different means of adsorption: onto internal surfaces, into the molecular structure, as free gas in fractures, cleats, and voids. Additional process is the dissolution of CO2 in groundwater. Adsorption process leads to CO2 bonding with the coal causing the gas to be physically trapped on the coal when sufficient pressure is maintained. According to Ceglarska and Zarebska [55] adsorption is considered as the most important process for CO2 retention in coal. Another important insight is that when the gas is sorbed into the coal, processes of adsorption and gas penetration of the solid matrix often leads to the coal swelling [56]. Successful storage of CO2 in coal seam requires sufficient permeability along pores and fractures. Storage of carbon dioxide can be connected with recovery of methane (CH4) which sometimes is trapped within the coal seams. This process is called CO2 – Enhanced Coalbed Recovery (CO2 –ECR) and it is similar to the CO2 – EOR [57], presented in Figure 15. Coal Seam Methane, or Coal Bed Methane is an inherent part to coal and forms during the coalification.. 33.

(34) Figure 15. Concept of enhanced coalbed methane (ECBM) enabling exploitation of the natural gas (methane) found in coal, combined with CO2 storage (CCUS, 2011).. There are two methods to recover methane from the coal deposits. First one uses pressure gradient between underground seam and atmospheric pressure. Second one is called Enhanced Coal Bed Methane Recovery. In this technology pressure gradient is achieved by various induced or artificial processes: dewatering, hydraulic fracturing or injecting another gas to decrease the partial pressure of natural gases present in the reservoir. The gases injected are commonly N2, CO2 or a mixture of them, and this process is called displacement desorption. When CO2 is injected into coal, its molecules get entirely adsorbed on the coal micropores and if there is methane, they replace the methane molecules which diffuses through the pore spaces in the matrix and flows through the fractures or cleats. This phenomenon happens because coal display higher sorption affinity towards CO2 than CH4 due to the higher adsorption energy and smaller molecular diameter of CO2. Collected CH4 is collected and used as source of energy. The replacement of CH4 by CO2 in coal, reduces anthropogenic CO2 and adds to reduction of climate change while providing methane recovery, creating additional energy for sustainable development. Nevertheless, it is important to point that the recovered CH4, when combusted will emit CO2 to the atmosphere. In 1995 first CO2- EMR project was tested in San Juan Basin, New Mexico, U.S. It helped to identify problems which can be faced during the process, caused decreasing formation permeability and slow rates of CO2 injections. Following tests were done in: Fenn and Big Valley (Canada), Isikari coal fields (Japan), Upper Silesian basin (Poland), Quinshui Basin (China), Appalachian Basin (USA), Illnois Basin (USA) and Black Warrior Basin (USA). Field experiment ‘RECOPOL’ in Upper Silesian Basin in Poland (Fig.16) started in August 2004 by CO2 injection in three seams of Carboniferous age, placed at depth between 900-1200 m [58].. Figure 16. RECOPOL Project location (F.V. Wageningen, 2009). 34.

(35) This pilot project was build next to the existing well for methane recovery to establish a baseline production. Consequent injections of 14-5 tons of CO2/day were done till April 2005. Used medium was a liquid CO2 from an industrial source. During the tests fracturing of the seam was done because of the reduction of permeability of coal, potentially due of its swelling. Also, the injection pressure had to be twice higher than the reservoir pressure Total of 760 tons of CO2 were injected during the whole testing. Methane production increased significantly during the CO2 injections, when compare to the baseline production. It is predicted that in the Upper Silesian Basin district coal seams with higher permeability, thicker seams and higher gas content are existing where the next projects could take place [59].. 35.

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(37) Chapter 3. Mineral carbonation. Mineral carbonation (MC) is a process of CO2 fixation in the form of stable carbonate minerals, i.e. calcite (CaCO3), magnesite (MgCO3) or siderite (FeCO3), which was first described by Lackner et al. in 1995 [60]. In nature, this process is called silicate weathering and occurs over geologic times with a very slow kinetic. Silicates act as a source of alkaline and alkaline-earth metals which reacts with carbon dioxide. Process of carbonation usually refers to simple 2-step chemical reaction producing stable magnesium carbonates or calcium carbonates [61]. Firstly, hydration of the calcium/ magnesium oxide occurs followed by carbonation of calcium/magnesium hydroxide:. 1. CaO + H2O → Ca(OH)2 Ca(OH)2 + CO2 → CaCO3 + H2O 2. MgO+H2O→Mg(OH)2 Mg(OH)2 + CO2 → MgCO3 + H2O. (1) (2). (3) (4). The potential of CO2 storage in the Earth’s crust in form of carbonates is substantial. Current total mass of CO2 in the atmosphere is equal to 800 Gt, while 39 000 000 Gt of carbon exist in rocks, in the form of marble, limestone and chalk [62]. Next to silicates, another resource that can be used for mineral carbonation, are industrial wastes which are rich in alkaline metals, like Ca, Mg or Fe [63], as presented in Figure 17 [64]. Nevertheless, from the storage perspectives, magnesium based silicates are favored as significant amounts of them are available worldwide and in theory they could bind all fossil fuelproduced carbon.. 37.

(38) Figure 17. CO2 as feedstock for mineral carbonation (Global CCS Institute, 2014).. Magnesium silicates can be divided into: olivine [(Mg,Fe)SiO4], forsterite (MgSiO4), serpentine [Mg2Si2O5(OH)4] and some other smaller groups with less quantity. The full list of all natural minerals studied for carbonation includes: basalt, brucite, chrysolite, dunite, forsterite, harzburgite, olivine, orthopyroxene, peridotite, pyroxenite, serpentine, serpentine and wollastonite. Oxides and hydroxides of Ca and Mg are good materials for the carbonation and they can be found in mafic and ultramafic silicate minerals which can be carbonated as carbonic acid (H2CO3, pKa = 6.3) is more acidic than silicic acid [Si(OH)4, pKa = 9.5]. Rocks containing magnesium silicate display high MgO concentration (up to 50% by weight) than rocks with calcium silicates (i.e. basalts) with CaO content of around 10% meaning smaller theoretical CO2 storage capacity. High amount of the metal oxides is important as it mean lower factor of RCO2 (ratio of the mass of mineral needed to the mass of CO2 fixed with complete conversion assumed). Specific data is presented in Table 2 [60].. Table 2. Compositions of minerals and their CO2 specific storage characteristics (Lackner et al., 1995).. Rock. MgO (wt%). CaO (wt%). RCO2 (ton rock/tonCO2). Olivine. 49.5. 0.3. 1.8. Serpentine. 40. -. 2.3. Wollastonite. -. 35. 3.6. Talc. 44. -. 2.1. Basalt. 6.2. 9.4. 7.1. 38.

(39) Figure 18. In situ carbonation - The Carbfix Project (Carbfix, 2014).. There are two types of carbonation processes: ex-situ (Fig.17), where the reaction is held in a chemical plant and silicates are mined before the reaction and undergo pre-treatment; in-situ (Fig.18) [65], where CO2 is injected into silicate-rich geologic formations. In ex-situ process carbon dioxide is transported from the source place to the carbonation reactor, combined with crushed Ca/Mg – bearing minerals and if appropriate conditions are met, the reaction will take place. After the process products are separated, collected and used as a raw material or transported back to mining site. Carbonation reaction is exothermic [66]. Depending on the substrate more or less heat can be released during this process. The exothermic effect of the silicates carbonation is smaller when compare with reaction with Mg(OH)2 or Ca(OH)2. Olivine: Mg2SiO4 + 2CO2 → 2MgCO3 + SiO2 + 90 kJ/mol. (5). Wollastonite: CaSiO3 + CO2 → CaCO3 + SiO2 + 90 kJ/mol. (6). Serpentine: Mg2Si2O5(OH)4 + 3CO2 → 3MgCO3 + 2SiO2 + 2H2O + 64 kJ/mol. (7). Carbonate phases are thermodynamically favored to form during the reaction between CO2 and silicates [61]. As this reaction release heat, low temperatures are suitable for the reaction to occur. In 39.

(40) temperatures above 900⁰C (for calcite) and 300⁰C (for magnesite) and CO2 partial pressure equal 1 bar reverse reaction follow, called calcination. Problematic aspect that arise through the reaction is the formation of silica or carbonate layer over the substrate surface which tends to hinder further reaction and limits the conversion rate [67]. The research concerning carbonation trying to solve this issue by accelerating the process and increase the kinetic rate. As stated before, next to natural minerals industrial alkaline wastes can be used for carbonation process. Most of them are easily accessible at low cost, they have high reactivity, can be found at close proximity to the CO2 sources and the reaction itself can change their properties and increase its utilization. Studies show that the successful process doesn’t need as extreme conditions as for ultramafic rocks and high conversion rate is achieved [68]. Nevertheless, industrial waste production is not enough to cover whole CO2 emissions as can be achieved in case of natural minerals. The list of all studies alkaline waster for MC includes: argon oxygen decarbonization slag, air pollution control fly ash, biomass ash, blast furnace slag, bottom ash, industrial brines, cement wastes, chrysolite mining tailings, coal-combustion fly ash, ladle slag, lignite-combustion fly ash, mine tailings, municipality ash, nirex reference vault backfill, oil shale ash, paper mill waste, paper wastewater incineration ash, pressed limewaste composites and steelmaking slag [69–71]. Mine tailings are generated during mining activities and although they are classified as wastes, most of them contain minerals.. 3.1 Ex-situ mineral carbonation Different process routes have been developed in order to optimize carbonation, namely ‘ex-situ route’, ‘in-situ route’ and ‘other MC routes’ (Fig.19) [72,73]. Ex-situ process is an aboveground carbonation of alkaline-bearing materials through chemical processes. This route is usually 2-step, involving pre-treatment of the material and following sequestration. In case of rocks, pre-treatment involves mining, crushing, milling prior to carbonation in order to increase the reactive surface of substrate. Two different concepts of this method have been identified: direct and indirect methods. In direct technology, carbonation is maintained in single step and can be conducted either as gas solid dry reaction or in an aqueous solution. In case of indirect method, reactive metals are first extracted from the waste or rock and carbonated as a separate step. There are three main challenges regarding the implementation ex-situ MC on industrial scale. With current technology development there are large energy costs and a need to accelerate the process in order to make it efficient. Also, large amounts of silicates are needed to sequester considerable amounts the carbon dioxide. 4 MW power plant emits 1.1 Mt of CO2. To capture that, 6.4 Mt of forsterite (the most efficient silicate to fix CO2) would be needed to utilize that amount of carbon dioxide. This process would result in creation 2.6 million cubic meters of magnesite. In addition to that forsterite is 40.

(41) only one among of a number of different minerals in a rock so the total mass of rock required to utilize CO2 is much bigger. Ex-situ carbonation operations are characterized by high cost demanded by transport of minerals to the carbonation reactor, grinding the material, heating the system and store/dispose the final product. Extent of this operations influence the final cost of carbonation. It was found that the final cost of only carbonation would be around of 54$/tone of CO2 [74]. Additional costs, for example associated with mining and moving the rocks and its final storage significantly increase the final price. Placing the carbonation reactor in a close proximity to the CO2 emission source would results in no additional cost related to the gas transport. Different possibility is the direct CO2 capture from the air and using it for carbonation.. Direct carbonation methods Gas-solid dry carbonation In this route, alkaline solid is reacting with gaseous CO2, usually at increased pressure and temperature. Only a few research groups are still investigating gas solid carbonation of reactive waste, as conditions of this process were not sufficient for silicates. Most of the studies of dry carbonation of natural minerals brought insignificant or negligible results, even at high pressures. Montes – Hernandez et al. [75] achieved high carbonation extent ( more than 0.9) using CaO in isothermal conditions at 600 and 800⁰C and much lesser carbonation conversion rate for Ca(OH)2 in 400 ⁰C. Till very recent studies involving dry carbonation was practically abandoned as this reaction has very slow reaction rate and only examples of successful dry carbonation on industrial waste are presented [76–79]. Exergy analysis of direct dry carbonation shows that this process has positive net exothermic effect [66]. It is also proven that addition of small amount of water vapor to the reaction accelerates it [80]. Some researchers are trying to activate the substrates by heat treatment, but it strongly affects the economic feasibility of carbonation [81]. The topic of gas solid dry carbonation will be resumed in the experimental part of this thesis, as substantial part of this research is based on this method.. 41.

(42) Figure 19. Mineral Carbonation process routes (A. Olajire, 2013).. Aqueous carbonation Direct wet carbonation in a single reactor is divided into 3 phases. In first one, CO2 dissolves in the water and transforms into carbonate ion, changing the environment into acidic one: CO2(g) + H2O(l) → H2CO3(aq) → H+ + HCO3-(aq). (8). Second phase involves metals leaching from the mineral matrix: (Ca/Mg)-silicates(s) + 2H+(aq) → (Ca/Mg)2+(aq) + SiO2(s) + H2O(l). (9). Final stage concerns the carbonates precipitation: (Ca/Mg)2+(aq) + HCO3-(aq) → (Ca/Mg)CO3(s) + H+(aq). (10). The general knowledge regarding this route is that silicate dissolution is the rate limiting step of the whole process. Most of the science effort is made to improve the kinetics of the second step by varying the process conditions: temperature, pressure, CO2 flow rate, solid to liquid ratio, decreasing the particle size, changing the pH or adding catalysts [82]. Silicate dissolution step can differ among the minerals. For example, serpentine dissolution is divided into 2 steps: rapid dissolution followed by comparatively slower phase. Studies done on mechanism of wet carbonation indicate the dissolution step could be improved by increasing the particles specific area or removal of the SiO2 layer. 42.

(43) Indirect carbonation methods The difference between direct and indirect routes is that the second group is divided into two or even more steps, most likely in separate reactors. The benefit of such division is that they can be optimized separately, independently from each other.. Multi-step gas-solid route This process is divided into conversion of Ca/Mg-based silicate to (Ca/Mg)(OH)2 hydroxides. This route have been developed by Zevenhoven et al. [83] and two alternative methods for serpentine carbonation via MgO and Mg(OH)2 are presented in Figure 20.. Figure 20. Two alternative routes for serpentine carbonation through MgO or MG(OH) 2 (Zevenhoven et al., 2008).. First, either MgO or Mg(OH)2 is produced from serpentine as direct carbonation from magnesium silicate cannot be achieved at sufficient chemical rate. Production of magnesium hydroxide is led upon addition of water vapor, as follows:. Mg3Si2O5(OH)4(s) → 3MgO(s) + 2SiO2(s) + 2H2O. (11). MgO(s) + H2O → Mg(OH)2(s). (12). Mg(OH)2(s) + CO2 → MgCO3(s) + H2O(l). (13). Route I - Two – step serpentine carbonation through MgO (Fig.20): 43.

(44) MgO is produced in atmospheric pressure and around 600⁰C. Next, carbonation process is held at supercritical pressure of CO2 (~73 bar) and temperatures of up to 600⁰C. Route II – Three – step serpentine carbonation through Mg(OH)2 (Fig.20): First step is the same one as for route I. Following that, hydration of MgO occurs at elevated pressure and temperature in order to improve the kinetics. Third step is again the same as for route II. According to the author of this process, this route has better energy efficiency and exhibits faster kinetics.. Currently this processes are being optimized at Åbo Akademi University (AA). Still, the production of Mg(OH)2 needs more heat than is generated by following process of carbonation. However, it has better energy economics when compared to straightforward carbonation (0.9–1.2 vs. 1.0-2.3 kWh/kg CO2 sequestered).. Indirect aqueous carbonation Similar to the gaseous indirect carbonation, this process is characterized by separation into two steps: extraction of the Mg/Ca and carbonation. Usually independent steps are done with use of different additives. To achieve high purity of carbonation products, recovering of additives has to be done and in general it is a problematic step. HCl extraction route Extraction of metals by the hydrochloric acid is easy process to perform as this additive has very low Ph. This route was first proposed by Lackner et al. (1995). Process using serpentine as a raw material, is described below: Mg3Si2O5(OH)4(s) + 6HCl(l) + H2O(l) → 3MgCl2·6H2O(aq) + 2SiO2(s). (14). 2MgCl(OH)(l) → Mg(OH)2(s) + MgCl2(l/s). (15). Mg(OH)2(s) + CO2(g) → MgCO3(s) + H2O(l/g). (16). Main challenges associated with this method is the costs imposed by the use of HCl, for example makeup or need to use anti-corrosion materials. Energy consumption of the whole process significantly exceeds the energy produced at power station. Cost of 1 tone of CO2 sequestered were calculated as 150 U.S dollars [84].. HCl/HNO3 extraction route Another acid used for the first step in aqueous route is HNO3. Studies of extraction magnesium from serpentine by nitric acid were described by Teir et al. (2007) [85]. Mg3Si2O5(OH)4(s) + 6(HNO3/HCl)(aq) → 3Mg2+(aq) + 6(NO3-/Cl-)(aq). (17). 5Mg((NO3)2/Cl2)(aq) + 10NaOH(aq) + 4CO2(g) → 10Na(NO3/Cl)(aq) + Mg5(OH)2(CO3)4 ·4H2O(s). (18) 44.

(45) Firstly, serpentine is dissolved in 4M HNO3 or HCl at 70⁰C. Next, excess of solvent is evaporated and magnesium salt is produced. In the following step of carbonation, NaOH is added in order to increase the Ph, because of the acidity of the salt solution [Mg((NO3)2/Cl)(aq)]. Serpentine conversion to hydromagnesite of the experiment was found to be 83% using nitric acid and 70% using hydrochloric acid. The consumption of the materials in order to produce 1 ton of CO2 was respectively: 2.4 tone NaOH, 3.6 tone HNO3 or 2.1 tone HCl.. Acetic acid route This process was reported as sufficient for wollastonite and industrial waste processing [86]. Below reactions involving carbonation of wollastonite are presented: CaSiO3(s) + 2CH3COOH(l) → Ca2+(aq) + 2CH3COO-(aq) + H2O(l) + SiO2(s). (19). Ca2+(aq) + 2CH3COO-(aq) + CO2(g) + H2O(l) → CaCO3(aq) + 2CH3COOH(l). (20). Energy consumption of 20 MW has been calculated for a power plant with 100 MW power production. The cost of 21€/1 tone of CO2 fixed has been estimated. The process is presented in Figure 21 [87]. The main advantage of this process is lowering the cost of additives as HCl is not needed and associated cost with using it is eliminated.. Figure 21. Process scheme of acetic acid route (Kakizawa et al., 2001).. 45.

(46) Recyclable ammonium salts extraction Wang and Maroto-Valer (2011) [88] created a pH-swing CO2 carbonation process with use of recyclable ammonium salts (Fig. 22).. Figure 22. Process route of pH-swing CO2 sequestration with recyclable ammonium salts (Wang and Maroto-Valer, 2011).. In this route NH4HSO4 is used as an additive to extract Mg from serpentine. PH of the process is increased by adding ammonia. This leads to extraction of iron (if present) and silica from the mix:. Mg3Si2O5(OH)4(s) + 6NH4HSO4(aq) → 3MgSO4(aq) + 2SiO2(s) + 5H2O(l) + 3(NH4)2SO4(aq). (20). NH4HSO4(aq) + NH3·H2O(aq) → (NH4)2SO4(aq) + H2O(l). (21). 40% excess of NH4HSO4 is used to intensify Mg extraction. To obtain pure magnesium carbonate, impurities like Fe, Al, Cr, Zn, Cu and Mn are discarded from the mix by further increasing the pH. Hydromagnesite is obtained by reaction with NH3 and NH4HCO3 as follows: MgSO4(aq) + NH4HCO3 + NH3·H2O(aq) + 2H2O(l) → MgCO3·3H2O(s) + NH4HSO4(aq). (22). Last stage of the process is the regeneration of NH4HSO4(aq) and NH3 by thermal decomposition of (NH4)2SO4.. 46.