DET NORSKE VERITAS. Report Activity 3: CO 2 capture, compression and conditioning GASSNOVA SF

Transcription

1 Report Activity 3: CO 2 capture, compression and conditioning GASSNOVA SF Report No./DNV Reg No.: / 13REPT4-2 Rev 1,

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3 No distribution without permission from the client or responsible organisational unit (however, free distribution for internal use within DNV after 3 years) No distribution without permission from the client or responsible organisational unit Strictly confidential Unrestricted distribution Indexing Terms Key Words Service Area Market Segment Rev. No. / Date: Reason for Issue: Prepared by: Verified by: Accepted by: 2010 Det Norske Veritas AS Reference to part of this report which may lead to misinterpretation is not permissible. Date : Page ii of iii

4 Table of Contents EXECUTIVE SUMMARY INTRODUCTION MAIN REPORT CO 2 capture technologies CO 2 point sources impact on technology CO 2 capture technology vendors Compression and conditioning Project overview Technology qualification procedures Review of publicly available reports CONCLUSIONS REFERENCES Appendix 1 Appendix 2 Appendix 3 Large Scale Integrated CCS Projects Pilot Scale CCS Projects Maturity assessment of CO 2 capture technologies (CONFIDENTIAL) Date : Page iii of iii

5 EXECUTIVE SUMMARY Gassnova has been given the mandate from the Norwegian Ministry of Petroleum and Energy (MPE) to do a research work with the objective to contribute to a wide and updated mapping of the opportunities for realisation of full scale CO 2 capture and storage beyond the Mongstad project. This work is called the Norwegian CCS (NCCS) Study. DNV has been asked to do an initial information gathering study prior to the NCCS. The initial information gathering is divided into six activities. The focus of this report is Activity 3 CO 2 capture, compression and conditioning. The scope of work for Activity 3 covers the following aspects as proposed by Gassnova: Prepare a summary of existing publicly available reports: The Global Status of CCS: 2011 by GCCSI; CCS Technology Roadmap by IEAGHG Prepare a market overview of CO 2 capture technology vendors: activities, projects, technology maturity Prepare an overview of CCS projects (both full scale and pilot scale): status, industry, CO 2 capture technology, size, CO 2 capture technology supplier Identify potential differences in CO 2 capture from natural gas-, coal-, biomass fired power plants and industrial sources Evaluate when available CO 2 capture technologies are qualified Identify and evaluate qualification procedures and associated technology qualification activities for identified projects This report systematically documents the findings of publically available information by mapping the above sub-activities into different sections in the main body of the report. The report mainly focuses on CO 2 capture technologies including different approaches as how to capture CO 2 from different source including power plants and industrial processes. Within this context, the technical principles for post-combustion, pre-combustion and oxy-fuel combustion capture technologies are briefly explained and main challenges associated with commercialization of these technologies at large scale are reviewed. Different industries producing CO 2 (other than power industry) and potential options as how to capture the CO 2 emitted by them are explained and discussed. Main aspects related to CO 2 compression and conditioning technologies are also presented. Examples of capture technologies from difference flue gases including coal, gas and steel production facility is discussed. The difference is shown to arise from the specification (i.e. composition, temperature and pressure) of the flue gases produced which will dictate what kind of processes (including process units, equipment and solvents/catalysts) that have to be applied in order to fulfil the requirements for the CO 2 capture plant. With respect to commercial aspects of CO 2 capture technologies, the present report specifically focuses on the CO 2 capture technology vendors. The most active vendors in the CCS market are identified for post-combustion, pre-combustion and oxy-fuel combustion technologies. Each vendor is described in terms of size (annual revenue and number of employees), main market and projects that they are currently involved in. In addition to the overview of technology vendors, this report provides an overview of large scale and pilot scale CCS projects worldwide. The list of large scale projects is based on the recent Global CCS Institute report: Global status of CCS (2011). The present report provides an overview of the project in operational, execution, definition stages and selected project in the evaluation stage. Date : Page 4

6 Projects in the evaluation stage were selected based on submissions for NER 300 to the European Commission. According to Global CCS institute the following projects within power and industrial application (excluding natural gas processing) have passed Final Investment Decision (FID) gate: Operation: Edin Fertilizer Project (industrial CO 2 capture) Operation: Great Plains Synfuels Plant and Weyburn-Midale Project (industrial CO 2 capture) Execution: Illinois Industrial Carbon Capture and Sequestration Project (chemical production - industrial CO 2 capture) Execution: Boundary Dam Integrated Carbon Capture and Sequestration Demonstration Project (post-combustion) Execution: Agrium CO 2 Capture with ACTL (industrial CO 2 capture from ammonia synthesis facilities) Execution: Kemper County IGCC Project (pre-combustion) A few of the above-mentioned projects include CO 2 capture from industrial plants/chemical facilities and two others aim at power based on post combustion and pre combustion technologies. These projects have been planned to start operating within the next four to five years. Given the challenges in development of hydrogen-fuelled turbines, the first of pre combustion projects will probably be using turbine systems similar to those in combined cycle gas turbines (CCGT) or re-designed gas turbines for syngas applications. Possible drawbacks will be producing less net power due to dilution of the fuel with steam or nitrogen to control the flame temperature and NO x emissions, or lowering the capture rate through burning carbon (CO) containing fuel. A rather broad approach is chosen to give an overview of maturity status for different CO 2 capture technologies based on publicly available information. Five different stages including conceptual design, laboratory or bench scale, pilot plant scale, full-scale demonstration plant, and commercial process was used. The status of each CO 2 capture technology (including post, pre and oxy-fuel combustion) at each maturity level is presented and discussed. It is shown that the maturity level for all three capture concepts is at pilot plant scale. This may be judged differently on a case to case basis if more detailed information is available such as information from specific applications, vendors, etc. When it comes to realization of the CCS industry, a brief discussion is given on the question of when CO 2 capture technologies will become commercially available for power plant application. A few roadmaps and predictions published by institutions such as US Department of Energy (DOE) and Electric Power Research Institute (EPRI) is presented and discussed. Most of these reports predict the first large scale post combustion CO 2 capture plant to be in commercial operation around There is no publicly available information on technology qualification procedures or guidelines applied in the different identified CCS projects described in this report. However, some available procedures and guidelines that can be used for qualification of CO 2 capture technologies, such as DNV s Recommended Practice on qualification of CO 2 capture technologies (DNV-RP-J201) and DOE s Technology Readiness Assessment Guide are introduced and discussed. Date : Page 5

7 1 INTRODUCTION 1.1 Gassnova Norwegian CCS study (NCCS) The NCCS project s main objective is to carry out an initial information gathering on the possibility of implementing Carbon Capture and Storage (CCS) in Norway. The goal is to contribute to a broad mapping of the possibilities for realization of full-scale CCS projects beyond the projects at Mongstad. The collected facts and figures are based on publicly available sources. DNV has not discussed and verified the information with the different sources. Gassnova SF (Gassnova) has requested DNV to conduct this study. The initial mapping and information gathering for the NCCS project consists of the following six activities: 1. Mapping and evaluation of processes and criteria that have been used nationally and internationally to identify evaluate and select full scale CCS investment projects 2. Identification and evaluation of existing and potential emission sources in mainland Norway 3. Mapping and assessment of projects, operators and maturity of relevant CO 2 capture technologies 4. Mapping and investigating status of identified CO 2 storage and utilization both nationally and internationally 5. Mapping and reviewing the status of identified CO 2 transport solutions nationally and internationally 6. Identification and evaluation of frameworks, commercial drivers, energy market, existing regulations and legislative relationships and commercial models This report focuses on Activity 3 CO 2 capture compression and conditioning. Date : Page 6

8 1.2 Description of Activity 3 This report documents the findings of Activity 3. The main objective of the activity is to identify and evaluate CO 2 capture technology providers, projects and maturity levels of relevant technologies. The scope of work covers the following key elements: Prepare a summary of the following existing publicly available reports: The Global Status of CCS: 2011 by GCCSI; CCS Technology Roadmap by IEAGHG Prepare a market overview of CO 2 capture technology vendors: activities, projects and technology maturity Prepare an overview of CCS projects (both full scale and pilot scale): status, industry, CO 2 capture technology, size, CO 2 capture technology supplier Identify potential differences in CO 2 capture from natural gas-, coal-, biomass-fired power plants and industrial sources Evaluate when available CO 2 capture technologies might be qualified Identify and evaluate qualification procedures and associated technology qualification activities for identified projects The report is based solely on publicly available sources. Date : Page 7

9 2 MAIN REPORT 2.1 CO 2 capture technologies According to IPCC there are four basic concepts for capturing CO 2 from use of fossil fuels and/or biomass: Capture from industrial process streams Post-combustion capture Pre-combustion capture Oxy-fuel combustion capture These systems are shown in simplified form in Figure 1. Figure 1: Overview of CO 2 capture concepts. Image source: IPCC ( 1). In post-combustion capture CO 2 is captured from flue gases produced by combustion of fossil fuels. Instead of being discharged directly to the atmosphere, flue gas is passed through equipment which separates and captures most of the CO 2. A more detailed description of post-combustion capture process is given in section Pre-combustion capture is a technique where the CO 2 is captured before burning the fuel in a combustor. The technique consists of a natural gas reforming or coal gasification step followed by water gas shift reforming of the gas, with subsequent steps for separation of CO 2 and H 2 to produce a H 2 -rich gas. A description of pre-combustion decarbonisation technology can be found in section In Oxy-fuel carbon capture (also called denitrogenation); the fuel is combusted using almost pure oxygen at near stoichiometric conditions. This creates a flue gas consisting of mainly CO 2 and H 2 O. An overview of oxy-fuel processes can be found in section Date : Page 8

10 CO 2 capture from industrial process streams has been performed for about 80 years, although most of the CO 2 that is captured is vented to the atmosphere. Examples of CO 2 capture in different industries can be found in section Types of CO 2 separation technologies The CO 2 separation technologies can broadly be classified under four categories: Absorption by solvents; Adsorption by sorbents Membranes Cryogenic separation In addition to these four main separation processes, there are several novel CO 2 capture technologies that cannot easily be grouped under these categories. An overview of CO 2 separation processes with related technologies is presented in Figure 2, and a brief description of these processes is given in the subsequent sections. Figure 2: Types of CO 2 separation technologies ( 1). The applicability of the different separation technologies in Figure 2 to the different CO 2 capture concepts in Figure 1, can be visualised as a CO 2 capture toolbox as shown in Table 1. In this table, separation tasks are listed for the various capture concepts. The current leading commercial options are shown in green colour. Date : Page 9

11 Table 1: CO 2 capture toolbox (based on the table from IPCC ( 1). Capture Concept Post combustion Pre combustion Oxyfuel combustion Separation task CO 2 /N 2 CO 2 /H 2 O 2 /N 2 Capture Process Absorption Chemical solvents Physical solvents N. A. Chemical solvents Adsorption Zeolites Zeolites Zeolites Activated carbon Activated carbon Activated carbon Membranes Polymeric Polymeric Polymeric Cryogenic Liquefaction Liquefaction Distillation Absorption According to IPCC chemical absorption uses organic and inorganic aqueous solutions to weakly bond with carbon dioxide forming intermediate compounds. Organic amines are able to react with carbon dioxide forming water soluble compounds from streams with low CO 2 partial pressure. They are distinguished in primary, secondary and tertiary forms. The primary amine, monoethanolamine (MEA), is currently the most widely used solvent. The MEA solution is contacted with flue gas in an absorber where CO 2 is absorbed by the solution. MEA reacts with CO 2 in the gas stream to form MEA carbamate. The CO 2 -rich MEA solution is then sent to a stripper where it is reheated to release almost pure CO 2. Inorganic solvents include potassium carbonate, sodium carbonate and aqueous ammonia. Soluble carbonate compound reacts with carbon dioxide to form bicarbonate. The latter, when heated, releases CO 2, regenerating the initial carbonate. There are two available systems using ammonia, the ammonia-based wet scrubbing and the chilled ammonia process (CAP). In principle, ammonia and its derivatives react with CO 2 by a range of mechanisms. For instance, ammonium carbonate, water and CO 2 react and form ammonium bicarbonate. Physical solvents form a weaker bond to CO 2 than chemical solvents, with the advantage of lower cost of re. Binding takes place at high pressure with the CO 2 released when the pressure is reduced. The only energy needed for CO 2 capture is the power required for gas pressurization. The amount of energy per tonne of CO 2 is proportional to the inverse of the CO 2 concentration in the gas. Specific physical solvents include cold methanol which is used in the Rectisol process, dimethylether or polyethylene glycol which is used in the Selexol process, propylene carbonate used in the Fluor process and n-methyl-2pyrollidone. Of the separation methods described above, chemical absorption is the preferred method at CO 2 concentrations lower than 10% (such as flue gases from gas-fired power plants), because its energy use is not particularly sensitive to low CO 2 partial pressures. Physical absorption is the preferred method at higher CO 2 partial pressures ( 1). Date : Page 10

12 Adsorption According to IPCC some solid materials with high surface areas, such as zeolites, molecular sieves and activated carbon, can be used to separate CO 2 from gas mixtures by adsorption, where chemical reactions between the adsorbent and CO 2 may or may not occur during the separation process. These processes operate on repeated cycles with the basic steps being adsorption and re. The re can be done by reducing the pressure, by so-called pressure swing adsorption (PSA), or by increasing the temperature, in temperature swing adsorption (TSA). Electrical and vacuum swing adsorption are also available techniques for re. Currently, adsorption is not considered attractive for large-scale separation of CO 2 from flue gas because the capacity and CO 2 selectivity of available adsorbents are low Membranes According to IPCC carbon dioxide may be recovered using membranes. Gas separation membranes are available as ceramic, polymeric and ceramic/polymeric hybrids. The driving force for separation is given by difference in partial pressure of gas species between the feed side and permeate side of the membrane. Gas separation membrane energy efficiencies can be higher than for absorption separation systems, as a limited pressure drop across the membrane is sufficient to achieve separation. Their modular design also allows their use in combination with small-scale modular fuel cells, foreseen as a power plant concept for the future. While membranes are widely applied for gas separation, they have yet to be applied at power plant scale. The disadvantage of membrane separation systems for CO 2 capture is that their separation efficiency is relatively poor and the purity of CO 2 is relatively low. Micro-porous solids are used as gas absorption membranes that work as contacting devices between the gas and the liquid phase, increasing the contact area, thus reducing the size of the scrubbing equipment. They have potential to reduce the mass transfer of undesirable gas phase components such as oxygen and nitrous oxide, which are known to degrade the alkanolamine solvent. Membranes are also applied for membrane reformers for hydrogen production in pre-combustion capture concepts. The reformer consists of a steam reformer equipped with hydrogen selective membrane modules of palladium-based alloy and nickel-based catalyst and can perform steam reforming reaction, water gas shift reaction and hydrogen separation at the same time without a shift converter and PSA. This process is called membrane-enhanced steam reforming. The permeate (hydrogen) can be combusted, whereas the CO 2 -rich retentate is further purified as appropriate Cryogenic separation Cryogenics take advantage of the critical pressures and temperatures of specific elements and compounds in a mixture and are commonly used today for purification of CO 2 in gas streams that already have high CO 2 concentrations. Cryogenic separation offers high recovery of CO 2, but the large amount of energy required to provide the refrigeration necessary for the process, particularly for dilute gas streams, is the major disadvantage. Date : Page 11

13 Novel technologies According to IPCC there are several novel CO 2 capture concepts being developed in the wake of the first large-scale commercial CO 2 capture projects. Some of these concepts are briefly delineated below: A number of solid sorbents can be used to react with CO 2 to form stable compounds at one set of operating conditions and then, at another set of conditions, be regenerated to liberate the absorbed CO 2 and reform the original compound. For example, lithium zirconate (Li 2 ZrO 3 ) and lithium silicate (Li 4 SiO 4 ) have been investigated as high temperature CO 2 absorbents. Desired features, such as large capacity, rapid absorption, wide range of temperature and concentrations of CO 2, and stability, make these compounds strong candidates for developing commercially competitive CO 2 adsorbents. In another concept, solid CaO-based sorbents can be applied for high temperature CO 2 capture (>500 C) from flue gas to form CaCO 3, which is regenerated in a parallel process to form pure CO 2 and the oxide is circulated back to the capture vessel. These types of sorbents are attractive for high temperature in-situ CO 2 capture in novel pre-combustion concepts. However, solids are inherently more difficult to work with than liquids, and no solid sorbent system for large scale recovery of CO 2 from flue gas has yet been commercialized. Biologically based capture systems are another potential avenue for improvement in CO 2 capture technology. These systems are based upon naturally occurring reactions of CO 2 in living organisms. One of these possibilities is the use of enzymes. An enzyme-based system, utilizing carbonic anhydrase in a hollow fibre contained liquid membrane, can achieve CO 2 capture and release by mimicking the mechanism of the mammalian respiratory system. The idea behind this process is to use immobilized enzyme at the gas/liquid interface to increase the mass transfer and separation of CO 2 from flue gas Post-combustion capture concept Main principles Post-combustion CO 2 capture refers to removal of CO 2 from the flue gas produced from fossil fuel combustion. There are several commercially available process technologies which can in principle be used for CO 2 capture from flue gases, however at a smaller scale than needed for CCS application. Comparative assessment studies have shown that absorption processes based on chemical solvents are currently the preferred option for post-combustion CO 2 capture. At this point in time, they offer high capture efficiency and the lowest energy use and costs when compared with other existing postcombustion capture processes. A simplified process schematic of post-combustion CO 2 capture by chemical absorption is shown in Figure 3. Date : Page 12

14 Figure 3: Schematics of post-combustion capture by chemical absorption. After cooling the flue gas, it is brought into contact with the solvent in the absorber. At absorber temperatures typically between 40 and 60 o C, CO 2 is bound by the chemical solvent in the absorber. The flue gas then undergoes a water wash section to balance water in the system and to remove any solvent droplets or solvent vapour carried over, and then it leaves the absorber. It is possible to reduce CO 2 concentration in the exit gas down to very low values, as a result of the chemical reaction in the solvent, but lower exit concentrations tend to increase the height of the absorber tower. The CO 2 -rich solvent (which contains the chemically bound CO 2 ) is then pumped to the top of a stripper. In the stripper, the CO 2 -rich solvent is heated in order to regenerate the solvent. A reboiler, supplied with extraction steam, normally from the turbine cycle, provides the heat for re of the solvent in the stripper. Consequently, CO 2 is released, producing a concentrated stream which exits the stripper and is then cooled and dehydrated in preparation for compression, transport and storage. From the stripper, the CO 2 -lean solution is cooled and returned to the absorber for reuse Potential challenges Post-combustion capture technology is characterised by the following challenges and uncertainties ( 3): High energy consumption for absorbent re and CO 2 compression Most major units need scale-up Process integration with CO 2 source (such as power plant) Large-scale equipment and process needs optimization Extended clean-up of exhaust gas including desulphurization Corrosion Solvent degradation Uncertainties of HSE properties of solvent (amines) degradations products Date : Page 13

15 Post-combustion CO 2 capture technology maturity The current state-of-the-art post-combustion CO 2 capture technologies that could be applied to fossil fuel power plants employ chemical solvents that preferentially absorb CO 2 from the flue gas and are capable of achieving 90 per cent or more CO 2 capture. Amine-based chemical solvents, such as aqueous MEA, have been utilized for about 80 years for removal of acid gases (CO 2 and H 2 S) from natural gas streams and to produce food-grade CO 2 for use in beverages and other products. However, amine-based chemical solvents have not been demonstrated at a large-scale adequate for fossil fuel power plants (typically 400MW power plant or higher). Figure 4 shows a high-level technology maturity assessment of various components in a post-combustion capture technology for power plant application. The scheme shown in Figure 4 is previously reported technology status given by ZEP ( 4). Since the ZEP study, the overall status for post-combustion systems has matured. The main changes since then are: Full system integration and optimization with the power plant has reached pilot plant level. One example here is Plant Barry Project in USA. There are currently several large-scale demonstration plants planned to be in operation around such as Boundary Dam Integrated Carbon Capture and Sequestration Demonstration Project. Capture process optimization including development of new solvents and scale-up has been studied in pilot plants. Demonstration plants are being built and are currently in the start-up phase. Demonstration units are expected to operate in the coming years, such as the Technology Centre at Mongstad (TCM). Figure 4: Maturity of post-combustion capture technology ( 4). Date : Page 14

16 2.1.3 Pre-combustion capture concept Main principles A simplified process schematic for pre-combustion CO 2 capture is shown in Figure 5. Figure 5: Schematics of pre-combustion capture process. The most common application of pre-combustion capture concept for coal fired plants discussed in the literature is Integrated Gasification Combined Cycle (IGCC) where CO 2 is captured from the syngas (composed of mainly hydrogen) prior to its combustion for power production. In the gasifier, fuel is converted into gaseous components by applying heat under pressure in the presence of steam and limited O 2. By carefully controlling the amount of O 2, only a portion of the fuel burns to provide the heat necessary to decompose the fuel and produce syngas, a mixture of H 2 and CO, along with minor amounts of other gaseous constituents. To enable pre-combustion capture, the syngas is further processed in a shift reactor, which converts CO into CO 2 while producing additional H 2, thus increasing the CO 2 and H 2 concentrations. An acid gas removal system can then be used to separate the CO 2 and H 2 S from the H 2. After CO 2 and H 2 S removal, the H 2 is used as a fuel in a combustion turbine combined cycle to generate electricity ( 1). When natural gas as is available as fuel, pre-combustion capture may also be applied through an Integrated Reforming Combined Cycle (IRCC) power plant. As with coal, the raw gaseous fuel is first converted to syngas via reactions with oxygen (or air) and steam a process called reforming. This is again followed by a shift reactor and CO 2 separation, yielding streams of concentrated CO 2 and hydrogen. This is the dominant method used today to manufacture hydrogen. If the hydrogen is burned to generate electricity, as in an IGCC plant, we have pre-combustion capture ( 5). Date : Page 15

17 Potential challenges Main challenges and uncertainties associated with pre-combustion capture technology are ( 3): High energy consumption for CO 2 separation and fuel gas processing Process integration Large-scale equipment needs optimization Combustion of H 2 -rich fuel in gas turbine power plants Coal gasification units need demonstration for power plant application Low plant availability: High consequence of plant downtime Extensive supporting systems requirements Pre-combustion capture can only be applied in new power plants and is not a retrofit option for the existing power plants Most of the uncertainty in the cost of an IGCC capture plant comes from the IGCC process, rather than the CO 2 capture process. However, new developments such as advanced shift reactors (multiple stage reactors with distributed feed syngas between them) has been shown to be able to reduce the steam requirement of the water gas shift reaction in comparison with conventional configurations, at CO 2 capture rates of approximately 85%. This reduction is of course at the expense of high capital costs but also increased revenues due to lower electric efficiency penalties, thus higher net electric outputs for IGCC power plants with CO 2 capture. Other new approaches such as integration of reforming, shift and capture stages in one vessel such as enhanced Sorption Reforming (ESR) has shown promising results in both energy efficiency and utility demand for the process. Moreover, the purity of hydrogen used in hydrogen turbine directly contributes the power produced. Development of hydrogen turbines that can handle nearly pure hydrogen will then have an impact on the profitability of the IGCC plants with CO 2 capture. A careful process design, integration and optimization of different sections of an IGCC plant with CO 2 capture is regarded as an opportunity to help realization of economically viable pre-combustion CO 2 capture technology Pre-combustion CO 2 capture technology maturity Chemical processes involved in pre-combustion concept are based on well-known and proven components used in the hydrogen, syngas and fertiliser industry. Industry has many years of experience from converting fossil fuels into a hydrogen-rich syngas. However, using syngas directly in large scale power production is a new application. Figure 6 illustrates maturity of various components in pre-combustion capture technology for power plant application. The scheme shown in Figure 6 is based on the previously reported status given by ZEP in 2006 ( 4). There are a number of announced project for full scale demonstration plants with pre-combustion CO 2 capture for both IGCC power (one is currently under construction in China) as well as biomass to liquids application ( 5). Another example of oncoming large scale pre-combustion CO 2 capture projects is the lignite fired IGCC plant at Kemper County in Mississippi by Mississippi Power. This is a 582 MW plant from which 3,5 million tonnes of CO 2 per annum will be captured and used for EOR purpose. The project began construction during 2011 and the plant aims to begin Date : Page 16

18 operation in It seems reasonable that at least a few of these projects will be materialized over next years. Although the development of hydrogen-fuelled turbines have progressed since the publishing of the ZEP report, it is anticipated that there are still issues requiring further development and demonstration at larger scale. Given the challenges in development of turbines fuelled with pure hydrogen, the first of pre combustion projects will probably be using turbine systems similar to those in combined cycle gas turbines (CCGT) or re-designed gas turbines for syngas applications. Possible drawbacks will be producing less net power due to dilution of the fuel with steam or nitrogen to control the flame temperature and NO x emissions, or lowering the capture rate through burning carbon (CO) containing fuel. Figure 6: Maturity of pre-combustion capture technology ( 4). Date : Page 17

19 2.1.4 Oxy-fuel combustion capture concept Main principles A simplified process schematic of oxy-fuel combustion CO 2 capture is shown in Figure 7. N 2 Fuel Steam turbine CO 2 Air O 2 Flue gas CO 2 + H 2 O Air separator Boiler H 2 O Condenser Figure 7: Schematics of oxy-fuel combustion capture process. The objective of oxy-combustion is to combust coal in an enriched O 2 environment by using pure O 2 diluted with recycled CO 2 or H 2 O. Flue gas recycle (~70 to 80 percent of the gas stream) is necessary to approximate the boiler combustion and heat transfer characteristics of combustion with air. New developments may reduce recycling and consequently the boiler size. The main products of combustion are CO 2 and H 2 O which then require condensing the H 2 O from the exhaust and purification of the CO 2 stream. Depending on transportation and storage requirements, other minor products of combustion (e.g., excess O 2, SO 2, and NO x ) could also require removal to produce a relatively pure CO 2 stream ( 1) Potential challenges Main challenges and uncertainties associated with oxy-fuel combustion CO 2 capture technology are summarised below ( 3): High energy consumption for O 2 production and CO 2 purification and compression Process integration Large-scale equipment needs optimization Combustion process not demonstrated at a larger scale Cooled CO 2 /H 2 O recycle required to maintain temperatures within limits of combustor materials Low plant availability: high consequence of plant downtime New thermodynamic properties for CO 2 /H 2 O mixtures Oxy-fuel combustion technology maturity Applicable to any boiler design, oxy-combustion process control during start-up, shutdown, and load changes should be similar to a conventional power plant. Oxy-combustion relies on conventional Date : Page 18

20 equipment that is already available at the scale necessary for power plant applications, and key process principles, such as air separation and flue gas recycle, have been proven in the past. The appeal of oxy-combustion is tempered by the relatively high capital cost and energy consumption for the cryogenic Air Separation Unit (ASU) and the lack of large-scale experience with the technology. Further improvements to the cryogenic ASU process and/or development of more cost-effective oxygen production technologies are necessary. To date, partially integrated oxycombustion systems have only been demonstrated at 30 MW or less. Scale up to a full-size integrated demonstration plant is required to reduce the risk necessary for industry adoption. Figure 8 illustrates maturity of various components in oxy-fuel combustion capture technology for power plant application. The scheme shown in Figure 8 is based on the previously reported status given by ZEP ( 4). Since the ZEP study, the overall status for oxy-fuel systems has matured. The main changes since then are: Full process integration and optimization with the power plant has reached pilot plant level. One example here is Vattenfall s plant at Schwarze Pumpe. There are currently several largescale demonstration plants planned to be in operation around such as OXYCFB 300 Compostilla project. The combustion process and boiler have been sufficiently tested at pilot scale to move into larger demonstration units. This is however still one of the main technical challenges with oxy-fuel combustion. Figure 8: Maturity of oxy-fuel combustion capture technology ( 4) Industrial process capture systems CO 2 has been captured from industrial process streams for about 80 years, although most of the CO 2 that is captured is vented to the atmosphere. Current examples of CO 2 capture from process streams Date : Page 19

21 are purification of natural gas and production of hydrogen-containing synthesis gas for the manufacture of ammonia, alcohols and synthetic liquid fuels. Other industrial process streams which are a source of CO 2 that is not captured include cement and steel production, and fermentation processes for food and beverages. The sectors, sources and technologies for industrial CO 2 capture are described in Table 2. Table 2: Sectors, sources and technologies in industrial processes 6). Sector Production process Capture technology High purity industrial sources Natural gas sweetening (onhore/offshore) Coal to liquids (CtL) Gas to Liquids (GtL) Ethylene oxide production Ammonia production There are a number of existing gas separation techniques such as membrane separation, chemical absorption using solvents including amine-based solutions monoethanolamine (MEA), methyldiethanolamine (MDEA) and hot potassium carbonate based processes, physical sorbent based process, pressure swing absorption (PSA) and cryogenic separation process. Selection of the appropriate process is dependent on a number of factors including end use specification, gas inlet pressure, cost, size, weight and maintenance needs Iron and steel Blast furnace Top gas recycling (TGR) Oxy-fuel blast furnace Direct reduction of iron (DRI) Pre-combustion (gasification) + pressure swing adsorption (PSA), Vacuum pressure swing adsorption (VPSA) or chemical absorption FINEX technologies Pressure swing adsorption (PSA) The HIsarna process Pressure swing adsorption (PSA) or Vacuum pressure swing adsorption (VPSA) Cement Kiln/calcination Post-combustion technology using chemical solvents, Oxy-fuel technology Refineries Hydrogen production Chemical absorption, PSA Hydrogen gasification residues Pre-combustion (gasification) + chemical absorption Fluidised catalytic cracking Post-combustion using chemical absorption, or oxy-fuel technology Process heat Post-combustion using chemical absorption, or oxy-fuel technology Date : Page 20

22 Natural gas sweetening Natural gas contains different concentration levels of CO 2, depending on its source, which must be removed. Often distribution grids require that the CO 2 concentration be lowered to around 1-2% by volume (although this amount varies in different places) to prevent pipeline corrosion, to avoid excess energy for transport and to increase the heating value of the gas. If the gas is to be converted to liquefied natural gas (LNG) the CO 2 concentration should be no higher than 50 ppm. Depending on the level of CO 2 in natural gas, different processes for natural gas sweetening (i.e., H 2 S and CO 2 removal) are available: Chemical solvents; Physical solvents; Membranes. Selection of the appropriate process is dependent on a number of factors including end use specifications, gas inlet pressures, cost, size, weight and maintenance needs of the equipment. Natural gas sweetening using various alkanolamines (MEA, DEA, MDEA, etc.), or a mixture of them, is the most commonly used method. The process flow diagram for CO 2 recovery from natural gas is similar to what is presented for flue gas treatment, except that in natural gas processing, absorption occurs at high pressure, with subsequent expansion before the stripper column, where CO 2 will be flashed and separated. When the CO 2 concentration in natural gas is high, membrane systems may be more economical. Industrial application of membranes for recovery of CO 2 from natural gas started in the early 1980s for small units, with many design parameters unknown. It is now a well-established and competitive technology with advantages compared to other technologies, including amine treatment in certain cases. These advantages include lower capital cost, ease of skid-mounted installation, lower energy consumption, ability to be applied in remote areas (especially offshore) and flexibility. The hundreds of commercial aqueous amine systems currently in operation typically vent the captured CO 2 to the atmosphere. Of these projects, three are at natural gas treatment plants (two in Norway, one in Algeria) in which the captured CO 2 is sequestered in deep geological formations to prevent its release to the atmosphere. One of these projects, the Statoil natural gas production facility (1 million tonnes of CO 2 captured annually) at Sleipner in the North Sea, has been operating since 1996 (the longest-running commercial CCS project) aiming at Offshore gas cleaning and geological storage. In the Snow White project in northern Norway at Statoil s LNG plant, CO 2 is captured and stored offshore. The reason for storage is to avoid the CO 2 taxes for offshore emissions. The capture capacity is approximately 0.7 million tonnes per year and this has been in operation since Hydrogen production Globally, around million tonnes (Mt) of hydrogen is produced each year, the majority of which is produced using fossil fuel feedstocks. Around half of the produced hydrogen is used in ammonia synthesis and around a quarter is used for hydrocracking in petroleum refining. The balance is used in methanol synthesis and in other industrial applications including Gas to Liquids (GTL) and Coal to Liquid (CtL) production. The processes used to produce hydrogen from fossil fuel or biomass feedstocks include steam reforming, auto-thermal reforming (ATR), partial oxidation Date : Page 21

23 (POX), and gasification. The choice of technology in any particular context depends on economics, the need for plant flexibility and the most appropriate feedstock source. A generalised schematic of the industrial hydrogen production process is shown in Figure 9. Figure 9: Generalised process flow for industrial hydrogen and syngas production 6. As mentioned above, there are number of hydrogen production processes, via gasification, partial oxidation or steam reforming. All routes involve the application of solid fuel gasification or natural gas reforming technologies to produce a syngas which is purified via a gas clean-up step to produce a reformed syngas mix or hydrogen (H 2 ) for use as feedstock for the production of various final products. The water-gas shift reaction process converts syngas to a mixture of CO 2 and hydrogen in varying amounts. In the case of hydrogen production, the CO 2 must be removed to produce a purified stream, whilst for synthetic fuel production, the water-gas shift conversion and gas clean-up steps are carefully controlled to optimise the H 2 /CO ratio. The hydrogen production processes here are also used in ammonia (and fertiliser) production, and for the manufacture of synthetic transport fuels (CTL and GTL), DiMethly Ether (DME) and methanol ( 6) Ammonia production Production of hydrogen using processes described in the previous section is the first step in the manufacture of ammonia in the Haber-Bosch process. The Haber-Bosch process involves the synthesis of hydrogen with gaseous nitrogen using an iron or ruthenium enriched catalyst at high temperature and high pressure. Around 80% of all ammonia manufactured worldwide is used to produce inorganic nitrogen based fertilisers. Other important uses of ammonia include the manufacture of nitric acid, nylon and other polyamides, refrigerants, dyes, explosives and cleaning solutions. The International Fertiliser Association (IFA) reports that the predominant source of hydrogen for ammonia production is natural gas, although coal also forms a significant proportion, especially in China. In terms of the preferred hydrogen production method, a variety of different techniques as described in the previous section are used. Date : Page 22

24 Ethylene oxide production Ethylene oxide is a colourless flammable gas produced by direct oxidation of ethylene in the presence of a silver catalyst. Because of its special molecular structure, ethylene oxide easily participates in the addition reaction, allowing it to easily polymerize into larger compounds. It therefore has a range of uses in the chemical sector. During the absorption stage of the production process, a stream of gas comprising of between % CO 2 by volume is removed and vented. In addition to water, small quantities of acetaldehyde and traces of formaldehyde are other byproducts of the process, and the presence of these chemicals may affect the selection of the most suitable capture technology ( 6) Iron and steel industries Iron is primarily produced in blast furnaces, in which coke, pulverised coal, sinter and bulk ore are heated to approximately 1 500ºC. It is technically possible to use CCS technologies to reduce direct emissions from the iron production process, primarily through alterations in blast furnace design, but also through modifications to other steel production routes. Perhaps the most advanced potential CCS technology for the iron and steel sector is the Top Gas Recycling Blast Furnace (TGR-BF). Blast furnace gases are rich in carbon monoxide and CO 2. Reforming this gas can result in CO 2 concentration levels of up to 60% which can then be further concentrated using chemical absorption techniques, transported and stored. For the TGR process to work most efficiently, oxygen is injected into the blast furnace instead of air. This reduces the amount of nitrogen and increases the concentration of CO 2 in the off-gas. However, The additional costs associated to use of oxygen should be considered in economic evaluation. In the near term, TGR-BF seems to offer a particularly promising approach to CCS in the sector since existing blast furnaces can be retrofitted with the new technology, thus avoiding the need for investment in a new plant while still achieving significant CO 2 abatement. In addition, the process delivers energy savings as the recycling of the purified gas reduces the coke and coal consumption of the blast furnace. This efficiency increase in part offsets the extra costs involved in capture and storage. Date : Page 23

25 Figure 10: Basic diagram of a blast furnace equipped with TGR with capture ( 6). The gas-based direct reduced iron (DRI) process is also potentially suited for CCS. The DRI process involves the conversion of iron ore to iron through the use of a reduction gas, normally natural gas which is chemically converted to hydrogen, carbon monoxide (CO) and CO 2. CO 2 capture is already widely applied in the DRI process in order to enhance the flue gas quality, although the captured CO 2 is normally vented. Due to the high cost of natural gas, DRI facilities are concentrated in few countries such as the Middle East and Latin America. Within the last decade, a small number of DRI installations have been combined with coal gasification installations, with the coal-derived syngas used as the reducing gas. This process may be particularly important for countries that have limited gas supplies but large coal reserves, such as India, China, and South Africa. CO 2 from the gasification process can be captured using precombustion technologies ( 6) Cement production Main principles Cement production is an energy intensive process, and emits a substantial amount of CO 2. The most energy intensive process in the production of cement is clinker burning. This involves gradually heating calcium carbonate (Ca 2 CO 3 ) with small amounts of additives in a kiln. At approximately 900 C, calcination occurs and CO 2 is released from the calcium carbonate. With additional heating, the process reaches a temperature of around 1450ºC, at which point the calcium oxide reacts and agglomerates with silica, alumina and ferrous oxide to form cement clinker. Post-combustion CCS options would not require fundamental changes in the clinkerburning process. These could be applied both to new kilns and as retrofits to existing plants. The most promising current technology options involve the chemical absorption of CO 2 from flue gases using amines, ammonia and other chemical solvents. Chemical absorption with alkanolamines is considered to be a proven technology and has an extensive history in the chemical and gas industries, although at a much smaller scale than would be necessary in the cement industry. Date : Page 24

26 All current pilot and demonstration projects for post-combustion capture both in industry and in the power sector are based on chemical absorption, mainly through the use of amine based systems. Oxy-fuelling uses oxygen instead of air in the cement production process to generate an almost pure CO 2 stream. Oxy-fuelling would require substantial alterations to existing cement plants, making it less suitable for retrofitting than post-combustion technologies. Two main CCS options for oxy-fuelling within the cement industry have been proposed: Partial capture fuel would be burned in an oxygen/co 2 environment with flue gas recycling in the pre-calciner but not in the rotary kiln. This would enable the recovery of a nearly pure CO 2 stream at the end of one of the dual pre-heaters Total capture fuel would be burned in an oxygen/co 2 environment with flue gas recycling in both the pre-calciner and the rotary kiln. This would enable the recovery of a nearly pure CO 2 stream from the whole process Refineries There are three significant CO 2 emission sources in refineries which have the high potential for carbon capture: Process utilities such as heaters, boilers and furnaces Hydrogen (H 2 ) production processes, such as steam reforming, emissions from combined heat and power units Coke burn-off from fluidised catalytic crackers (FCC). In the case of process heating through the use of furnaces and boilers, they account for 30-60% of the emissions. In this section, both post-combustion and oxy-fuel technologies for the abatement of CO 2 in furnaces and boilers are investigated and are covered. For H 2 production it account for 5-20% of CO 2 emissions from a refinery, yet it produces concentrated stream of CO 2 often at a high pressure. Thus, it offers a low-cost option for CCS deployment. Finally, CO 2 could also be captured in the combined heat and power (CHP) installations that could replace distributed boilers in some refineries, and also captured from fluidised catalytic cracking units. These capture options are dependent on the configuration of the refinery ( 7),( 8). CO 2 Capture from process heaters Post-combustion capture and oxy-fuel capture currently offer possibilities for reducing emissions from process heaters in refineries. Technologies that could potentially feature in the future in new build facilities include chemical looping combustion using refinery gas and pre-combustion capture in the production of hydrogen fuel for use in boilers and heaters. CO 2 capture from hydrogen production Between 5% and 20% of refinery CO 2 emissions are linked to the production of hydrogen (H 2 ). Hydrogen is a by-product of the catalytic reformer and fluid catalytic cracker (FCC) processes but as demand for H 2 has increased with changes in fuel specification (to reduce sulphur content of fuels by hydrodesulphurization), demand now exceeds supply from these processes in most refineries. To meet the increased demand, hydrogen is produced either through the steam methane reforming (SMR) of natural gas or through the gasification of heavy residues and fuel oil. The hydrogen produced in both these processes needs to be separated from other constituents in the flue gases. Date : Page 25