Carbon capture from power generation

Carbon capture from power generation 4.1

4

Introduction

The fundamental chemical process involved in the generation of power from carbon-based fuel is the exothermic oxidation of carbon, as described in Section 3.1, and since CO2 is the lowest-energy end-point of the oxidative reaction chain, its production is unavoidable. The elimination of carbon from power plant emissions therefore requires either: G

G

G

Decarbonation of the fuel prior to combustion (pre-combustion capture) Separation of CO2 from the products of combustion (post-combustion capture) Reengineering the combustion process to produce CO2 as a pure combustion product, obviating the need for its separation (oxyfuel or chemical looping combustion)

These approaches are illustrated schematically in Figure 4.1. As shown in the figure, the pre- and post-combustion approaches both require technologies to separate CO2 from a gas mixture comprising CO2 1 H2 or CO2 1 N2, respectively. For oxyfueling, the oxygen supply can be achieved either through a separation of O2 from air (O2 1 N2 1 trace gases) or by the delivery of oxygen to the combustion process in the form of a solid oxide (chemical looping). Some advantages and disadvantages of these capture options are summarized in Table 4.1. Several fundamental technology areas are in use or under development to address these gas separation challenges, including absorption, adsorption, hydratebased separation, membranes, chemical looping. and cryogenic separation systems. The application of these technologies to pre- and post-combustion capture and to oxyfuel/chemical looping combustion is outlined in the following sections, and the technologies are described in detail in Chapters 6
9.

4.2

Pre-combustion capture

Pre-combustion capture involves decarbonation by gasification of the primary fuel, commonly coal or biomass, to produce hydrogen through a combination of partial combustion, reforming and water
gas shifting (WGS) (Section 3.1), and the separation of CO2 from the resulting reaction product stream. The current development and demonstration focus of pre-combustion capture is on IGCC plants, using the process shown schematically in Figure 4.2, although in principle the approach is equally applicable to all integrated gasification systems

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00004-0 © 2017 Elsevier Inc. All rights reserved.

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N2

Post-combustion capture

Fuel Power and heat Air

CO2 Separation

CO2

Pre-combustion capture

Fuel

Gasification and reforming

CO2

CO2 Separation

Air, O2, Steam

H2

Power and heat

N2

Air Oxyfuel combustion

CO2

Fuel

Power and heat

O2 Air

N2

Air separation Chemical looping combustion

Fuel

CO2

Metal oxide reduction

Me

Power and heat MeO

N2

Metal oxidation

Air

Figure 4.1 Options for CO2 capture from power generation. Table 4.1 Advantages and disadvantages of capture options Capture option

Advantages

Disadvantages

Pre-combustion

Lower energy requirements for CO2 capture and compression; fully developed technology, commercially deployed at the required scale in other industries Fully developed technology, commercially deployed at the required scale in other industries Opportunity for retrofit to existing plant Mature air separation technologies available; very high [CO2] simplifies capture process Very high [CO2] simplifies capture process

Temperature and efficiency issues associated with hydrogen-rich gas turbine fuel

Post-combustion

Oxyfuel combustion

Chemical looping combustion

High parasitic power requirement for solvent regeneration; low [CO2] impacts capture efficiency High capital and operating costs for current absorption systems Costly and energy intensive air separation step; significant plant impact makes retrofit unattractive Immature technology, currently under development

Carbon capture from power generation

Air

Air separation

77

N2, Air

Combined cycle plant H2

O2 Coal

Gasification

Electric power

H2 CO CO2

WG shift

H2 CO2

Cleanup

Capture CO2

Steam

Sulfur

Compression

CO2 to transportation and storage

Figure 4.2 Pre-combustion capture IGCC process schematic. Table 4.2 CO2:H2 separation technologies for pre-combustion capture Technology area Currently developed technologies

Example technologies under development

Absorption-based separation (Chapter 6)

Novel solvents to improve performance; improved design of processes and equipment

Physical solvents (e.g., Selexol, Fluor processes), chemical solvents

Adsorption-based separation (Chapter 7) Chemical looping systems (Chapter 7) Membrane separation (Chapter 8) CO2 liquefaction Cryogenic separation (Chapter 9)

Sorption-enhanced water
gas shift (SEWGS) process; elevated temperature pressure swing adsorption Chemical looping combustion or reforming Metal and ceramic membrane WGS reactors; ion transport membranes Hybrid cryogenic 1 membrane processes

where hydrogen is the final syngas product, such as integrated gasification fuel cell systems (see Section 4.7). The separation of CO2 and H2 can be achieved using a number of technologies, as shown in Table 4.2, of which the use of physical solvents (such as the Selexol and Fluor processes, described in Section 6.2) is currently the most commercially developed. In this and similar tables below, underlined technologies are those that are currently deployed or close to being deployed in CCS projects. As well as the relatively higher CO2 concentration ([CO2]) in the gas stream (.20% in the H2 1 CO2 stream vs 5%
15% in a post-combustion flue gas stream), CO2:H2

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separation is somewhat easier than the post-combustion separation of CO2 and N2 due to the greater difference in molecular weights and molecular kinetic diameters for CO2 versus H2 than for CO2 versus N2. In addition to the further development of technologies related to CO2:H2 separation (i.e., advanced solvents, sorbents, and membranes), other aspects of precombustion capture processes that are being addressed by RD&D efforts include: G

G

G

G

Optimization of gasification process to use less steam (catalysts, flow configurations, and heat integration) Development of H2-fueled gas turbines (addressing combustion processes, including flameless combustion, burner design, heat transfer and cooling, materials impact, and operational aspects) Physical, energetic, and operational integration of pre-combustion capture process into an IGCC plant Integration of gasification with CO2 capture

4.2.1 Pre-combustion RD&D projects The European Union
funded European Technology Platform for Zero Emission Fossil Fuel Power Plants (ETP ZEP) exemplifies RD&D activity in the area of precombustion capture and was established in 2005 with the initial aim of enabling the commercial deployment of fossil-fuel power plants with zero CO2 emissions by 2012. This ambitious goal was subsequently reset to a 2020 timeframe for demonstration of commercial viability, and the remit extended to support rapid large-scale deployment post-2020.

R&D and pilot-scale testing A number of projects were initiated from 2004 onward to address some of the key technologies required to enable pre-combustion capture from IGCC plants, as summarized in Table 4.3. Much of the R&D focus for pre-combustion capture has been on the WGS reaction, because this is the area where the main energy penalty is incurred, due to the amount of steam used for the WGS reaction and the limited recovery of heat produced in the conversion. Current R&D topics include minimizing the heat loss and/ or the amount of steam used in the WGS, for example, by developing new shift catalysts which operate with less steam, alternative configurations of the WGS, and combining the WGS reaction with CO2 adsorption to separate CO2 within the WGS reactor. The ENCAP project concluded in 2007 that the technologies for ZEIGCC could be considered largely ready for full-scale demonstration, exceptions being the need for further design optimization and testing of burners for H2-rich combustion, and the optimization of turbine blade material for higher turbine inlet temperatures. Following a technology selection decision in 2007, the project planned to focus further work on the 30 MWth Oxyfuel pilot then under construction by Vattenfall at Schwarze Pumpe Power Plant site, Germany (see Section 4.4).

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Table 4.3 EU R&D projects addressing IGCC pre-combustion capture Project

R&D objectives

ENCAP (SP2) (leading partner, Vattenfall AB) 2004
7

Optimization of CO-shift conversion Modeling of H2-rich combustion and experimental validation Development and testing of burners for H2-rich combustion in gas turbines Hydrogen compatibility of turbine components Development of pre-combustion capture plant specifications Review of IGCC operational experience, focusing on operational problems, corrosion and plugging, and plant integration Analysis of further optimization potential Identification of technology development requirements for gasification and syngas cleaning Feasibility study for optimized zero-emission IGCC (ZEIGCC) Further development of the SEWGS following on from the CACHET (FP6) project Reduce energy penalty and cost per tonne of CO2 avoided through Optimization of sorbent materials Reactor and process design optimization Smart integration of SEWGS unit in an IGCC power plant Identification and development of new techniques for pre-combustion capture Development of advanced oxygen production technologies Further develop the key enabling technologies advanced in earlier (FP6) projects

COORIVA (leading partner, TU Frieberg)

CAESAR (FP7) (leading partner ECN) 2008
12

DECARBIT (leading partner SINTEF) 2008
12

The CAESAR project developed a proprietary hydrotalcite-based sorbent (ALKASORB1) with a substantially lower energy penalty when compared to Selexol and achieved its target cost of CO2 avoided below h25/t-CO2. A 35 t-CO2/ day pilot-scale follow-up (EU Horizon 2020 funded STEPWISE project; 2015
19) will apply the technology to CO2 removal from blast-furnace gases as the next step toward a full-scale SEWGS demonstration plant in 2020
2022. The world’s first pilot-scale testing of pre-combustion capture started operations in 2010 at the ELCOGAS 335 MWe IGCC at Puertollano, Spain, with 100 t-CO2/ day separated from a 3600 Nm3/h (B2%, 14 MWth) syngas slipstream using amine absorption. A slightly smaller scale pilot, using the Selexol process to capture 1.4 t-CO2/h from a 0.8% syngas slipstream (equivalent to 5 MWth), was conducted

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from 2011 to 2013 and the Nuon/Vattenfall IGCC plant at Buggenum in the Netherlands, with the objective of demonstrating and optimizing pre-combustion capture before full-scale deployment at the 1.3 GW Magnum CCGT plant at Eemshaven in the Netherlands (see below). The main efficiency loss associated with pre-combustion capture occurs in the WGS section, due mainly to the amount of steam used for the WGS reaction and the limited recovery of heat produced in the conversion. Current R&D focus for pre-combustion capture is on minimizing the amount of steam use in the WGS, for example, by developing new shift catalysts which operate with less steam, alternative configurations of the WGS, and combining the WGS reaction with CO2 adsorption.

Demonstration and early deployment projects Building on the ENCAP and COORIVA R&D results, the German energy company RWE Power has planned to construct an IGCC plant with CCS at its Goldenbergwerk site near Cologne in Germany. The gasification plant would be lignite-fueled, with a gross electrical output of 450 MWe, reducing to 360 MWe net after deducting the plant and CCS power utilization, and was initially expected to be commissioned at the end of 2014. A capture efficiency of 90% was targeted, and storage of the 300 t-CO2/h (2.6 Mt-CO2/year) captured in the plant was planned to be in a saline aquifer or depleted gas reservoir, with evaluation of potential storage sites expected to be completed in 2010. Figure 4.3 shows the overall project plan as laid out in 2008. A major risk recognized at project inception was the lack of an EU-wide legal and regulatory framework for CO2 transport and storage; because of this the Goldenbergwerk plant included an option to run without capture, and the project was put on hold in 2010 awaiting passage of the German Carbon Storage Law, which was required to enable storage site selection. Several other demonstration and commercial-scale pre-combustion capture projects have also been announced with the expectation of being operational by 2020, as shown in Table 4.4, and up-to-date project information can be found in the project databases listed under Resources in Chapter 2. The “on hold” status of many announced demonstration projects highlights some of the non-technical challenges faced by power plant operators and their partner organizations in pursuing CCS; nevertheless many new IGCC and CCGT plants are being commissioned “capture-ready,” examples being Duke Energy’s Edwardsport and TECO’s Polk IGCCs in the United States, and the Vattenfall/Nuon Magnum CCGT in the Netherlands.

4.3

Post-combustion capture

In post-combustion capture, CO2 is removed from the combustion reaction product steam—the flue gases—before emission to the atmosphere. Post-combustion

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Research and development projects ENCAP COORIVA Demonstration stage projects Power plant project Project development Engineering and approvals Construction and commissioning Plant start-up and operation CO2 transport and storage project Storage site screening and appraisal Exploration drilling at selected site Storage project approvals Construction and commissioning Pipeline planning and approvals Pipeline construction and tie-in Transport and storage operation

Figure 4.3 RWE pre-combustion capture demonstration plant project plan.

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Table 4.4 Pre-combustion capture demonstration and early deployment projects Project; operator and Project description partners

Planned (actual) start-up

Edwardsport IGCC; Duke Energy, USA

618 MW IGCC with capture planned 2012 (2013, plant CCS ready using physical absorption process but on hold due to storage site unsuitability) Kemper County IGCC; 582 MW lignite-fueled IGCC with 2016 3.5 Mt-CO2/year for EOR Mississippi Power, USA Coal-fired IGCC with 2 Mt-CO2/year 2016 (Stage II) Huaneng GreenGen; 2020 (Stage III) for onshore EOR; Stage II at Peabody Energy, 100 MW scale, Stage III at China 400 MW 175 MW coal-fired IGCC with Quintanna, Great 2018 2.1 Mt-CO2/year for onshore EOR Northern Power Development, USA Dongguan Taiyangzhou 800 MW coal-fired IGCC with 1 Mt- 2019 Power Corp., China CO2/year for EOR or storage in depleted gas reservoir Nuon Magnum; 1.2 GW multifuel plant (coal, 2020 Vattenfall/Nuon, Shell biomass, gas fired) with CO2 storage in North Sea oil and gas fields

capture is thus an extension of the flue gas treatment for NOx and SOx removal, made more challenging by the relatively higher quantities of CO2 in the gas stream (typically 5%
15%, depending on the fuel being used). A similarly wide range of technologies is available or under development to address the post-combustion CO2:N2 separation problem, as shown in Table 4.5. The use of chemical solvents, such as MEA (described in Section 6.1), is the most mature and is widely deployed for natural gas treatment, although many of the currently planned demonstration projects are expected to use the chilled ammonia process (CAP; Section 6.2.1). As well as technologies to address the gas separation challenge, several other aspects of the post-combustion process are also the focus of ongoing RD&D, notably: G

G

G

Integration and optimization of the post-combustion process within the power plant Environmental impact (including see Section 2.3) of the overall post-combustion capture process and specific solvent use Procedures for optimal post-combustion process operation under varying plant conditions

An alternative post-combustion capture approach that has been proposed is to use cooled, CO2-rich flue gases to feed bioreactors producing microalgal biomass

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Table 4.5 CO2:N2 separation technologies for post-combustion capture Technology area

Currently developed technologies

Example technologies under development

Absorption-based separation (Chapter 6) Adsorption-based separation (Chapter 7) Membrane separation (Chapter 8) Cryogenic separation (Chapter 9)

Chemical solvents (e.g., MEA, chilled ammonia) Zeolite and activated carbon molecular sieves

Novel solvents to improve performance (e.g., phase change solvents); improved design of processes and equipment Carbonate sorbents; calcium/chemical looping

Polymeric membranes

Immobilized liquid membranes; molten carbonate membranes

CO2 liquefaction

Hybrid cryogenic
membrane and hydrate
membrane processes

that would be used as a biofuel, by either direct combustion or gasification with subsequent liquid fuel production (biodiesel). This is discussed together with other industrial use options in Chapter 22.

4.3.1 Post-combustion RD&D projects A number of post-combustion capture systems using monoethylene amine stripping (Section 6.2.1) have been in commercial operation since the late 1970s, providing CO2 for industrial use; examples are the IMC Global operated plant at Trona, CA, capturing 800 t-CO2/day for brine carbonation from a coal-fired boiler, and AES Power operated plants at Warrior Run, MD and Shady Point, OH, capturing 200
800 t-CO2/day from coal-fired power plant flue gas slipstreams for refrigeration and food processing. These installations provide pilot-scale proof of this absorption technology. However, these installations have not been used as pilots to investigate scale-up to capture the full plant emissions, due to the limited quantity of CO2 required for the specific end users served by each plant. In view of the relative maturity of amine stripping as a post-combustion capture option, substantial R&D effort has been and continues to be applied to further improve the performance of this technology, as the most likely pathway toward rapid commercial deployment of CCS. Recent improvements have been both evolutionary—for example, a gradual reduction in energy penalty through improved process design and integration—and revolutionary—the emergence of phase change

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solvents being a significant example. Progress across the wide range of postcombustion capture technologies, as listed in Table 4.5, is summarized below and discussed in more detail in the following chapters.

R&D and pilot-scale testing The objects of some recently completed and ongoing international R&D projects investigating post-combustion capture are shown in Table 4.6. The European Union has funded a series of R&D projects, under the EC’s Sixth and Seventh Framework Programs (FP6/7) and the Research Fund for Coal and Steel (RFCS), beginning with the CASTOR project, which included among its aims the development of new sorbents for post-combustion capture with an energy consumption target of , 2 GJ/t-CO2 at 90% recovery efficiency and a cost of h20
30/t-CO2 avoided. The project scope included completion of pilot-plant testing to demonstrate reliable and efficient operation of post-combustion capture. The pilot plant was constructed and commissioned during 2005 and started operation in Table 4.6 EU R&D projects addressing post-combustion capture Project

R&D objectives

CASTOR (FP6) 2003
8 CESAR (FP7) 2008
11

Novel solvents to reduce energy penalty

CAOLING (FP7) 2009
12 CAL-MOD (RFCS) 2010
13 iCAP (FP7)2010
13

OCTAVIUS (FP7) 2012
17 HiPerCap (FP7) 2014
17

Novel (e.g., hybrid) solvent systems, building on CASTOR results High flux membranes contactors as an alternative to packed columns Improved modeling and integration studies at system and plant level Pilot testing validation of new solvents and plant performance Scale-up of CaO looping capture to 1 MW scale Supported by lab-scale studies on sorbent properties Development of simulation tools to support industrial-scale demonstration and deployment of calcium looping capture, including sorption kinetics, sorbent attrition, and regeneration Pilot testing of multiphase post-combustion solvent system Investigation of capture based on CO2 hydrate formation Development of thermodynamic models for multiphase solvents Membrane development for pre- and post-combustion applications Building on CASTOR and CESAR results Pilot test the DMXt process Build on CESAR results and reduce efficiency penalty by 25% Process design improvement to reduce capital and operating costs Identify, assess, and select two most promising new or emerging technologies to achieve a step change in capture performance Establish a technology roadmap for further development of the two selected new capture processes

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early 2006 at the 400 MWe pulverized bituminous coal-fired Esbjerg power station, operated by Danish energy company DONG Energy. The pilot plant captured 90% of the CO2 from a 5000 Nm3/h, 0.5% flue gas slipstream taken after wet FGD, yielding 1 t-CO2/h. A number of solvents were pilot-tested in 1000 hour tests, including 30 wt% MEA and two proprietary solvents, CASTOR-1 and CASTOR-2. The pilot testing validated the post-combustion capture process and resulted in energy consumption of 3.5 GJ/t-CO2 for the CASTOR-2 solvent, with the potential to reduce this to 3.2 GJ/t-CO2 with further plant heat integration, and indicated capture costs in the range of h35
37/t-CO2 avoided. Reduced solvent degradation and corrosivity were further benefits of the two CASTOR solvents when compared to MEA. Following on from the successful CASTOR results, 2000 hour tests were conducted during 2009
2010 at the Esbjerg pilot plant on the novel CESAR solvents but, recognizing the difficulty in achieving a step change in energy consumption from incremental solvent improvements alone, subsequent projects, including iCAP and HiPerCap, sought to broaden the research toward achieving such a step change.

Demonstration and early deployment projects These research and pilot-scale programs have led to the announcement of a number of demonstration-scale post-combustion capture projects with start-up planned in the years to 2020, as shown in Table 4.7. A demonstration-scale test facility has also been established at Statoil’s Mongstad refinery in Bergen, Norway, following the construction and start-up in 2010 of a 280 MWe plus 350 MWth natural gas
fired CHP plant. The European Table 4.7 Post-combustion demonstration and early deployment projects Project; operator and partners

Project description

Planned (actual) start-up

Mountaineer; American Electric Power

20 MW demonstration plant, 110 kt-CO2/year capture using Alstom CAP and geological storage 160 MW coal-fired plant retrofit, Shell Cansolvt capture process, 1 Mt-CO2/year for EOR with excess to saline aquifer storage 240 MW slipstream from 610 MW coal-fired plant, KM-CDR amine capture, 1.6 Mt-CO2/year for EOR 385 MW gas-fired plant retrofit, amine capture, 1 Mt-CO2/year to depleted gas field storage

2009
2011

Boundary Dam; SaskPower

Petra Nova W.A. Parish; NRG Energy, JX Nippon Oil and Gas Exploration Peterhead/Goldeneye; Scottish and Southern Electric, Shell

2014

2016

2020— project on hold

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Carbon Capture and Storage

CO2 Test Centre Mongstad (TCM) provides a 100 kt-CO2/year capture facility with options for capture both from post-combustion flue gas and from refinery operations. A range of capture technologies have been tested at TCM, including amine, other solvents, and CAPs (Figure 4.4), and work at the center has included the development of verification protocols to enable performance comparison of different absorption processes (see Thimsen et al., 2014). Other partners in the TCM are Gassnova, Shell, and Sasol. The largest of these projects will bring the demonstration of post-combustion capture up to the full scale of commercial deployment.

4.4

Oxyfuel combustion

Oxyfuel combustion requires the delivery of oxygen rather than air to the combustion chamber, so that the gaseous combustion reaction product is near-pure CO2 rather than a mixture from which CO2 needs to be separated. Oxygen may be delivered either as a gas stream, produced by the separation of O2 from air (effectively an O2 1 N2 binary mixture), or as a solid oxide in a chemical looping process. Table 4.8 summarizes the technologies that can be applied to oxyfuel combustion. Combined cycle gas turbine emissions

3 to 4% CO2

Amine absorption plant

N2 CO2

Other refinery emissions

13% CO2

Chilled ammonia process

N2

Figure 4.4 European CO2 Test Centre Mongstad configuration.

Table 4.8 O2:N2 separation technologies for oxyfuel combustion capture Technology area

Currently developed technologies

Example technologies under development

Adsorption-based separation (Chapter 7) Membrane separation (Chapter 8) Cryogenic separation (Chapter 9)

Zeolite and activated carbon molecular sieves Polymeric membranes

Perovskites and chemical looping technology Ion transport membranes; carbon molecular sieves Improvements in distillation processes

Distillation

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In addition to RD&D focused on improvements in air separation for oxygen supply, other aspects of the oxyfuel process that are the subject of current research include: G

G

G

G

Characteristics of oxyfuel combustion processes (heat transfer, ash properties and composition, fouling) for a variety of solid fuel types Impact on boiler and combustion system (e.g., fluidized bed) design, construction materials, and operation, including flexibility for air firing Optimization of existing flue-gas treatment technologies for specific oxyfuel conditions (CO2-rich flue gas stream) Optimization of air separation units (ASUs) to reduce energy requirement, improve efficiency, and optimize overall system integration

4.4.1 Oxyfuel RD&D projects In 2001 the Swedish power company Vattenfall AB, Europe’s third-largest power company, began a comprehensive RD&D program into oxyfuel combustion, which it had identified as the preferred option for lignite-fueled plants. Vattenfall generates . 40% of its power from fossil fuels, and the aim of the program is to develop oxyfuel technology for full commercial deployment by 2015 at a target capture cost of less than h20/t-CO2 avoided.

R&D and pilot-scale testing Between 2001 and 2007, five laboratory-scale test rigs were commissioned at universities in Sweden and Germany to investigate oxyfuel processes and performance, as summarized in Table 4.9. Following this laboratory-scale program, a 30 MW pilot plant was put into operation in September 2008 at the Schwarze Pumpe power plant in Germany as an intermediate step-up toward a full demonstration plant. This was the first oxyfuel pilot plant in the world, and the main objectives of the initial 3-year pilot program were: G

G

G

G

Validation of laboratory-scale results and engineering work for lignite and hard coal combustion Optimizing the integration of oxyfuel requirements into power plants Improving knowledge and gaining experience of oxyfuel combustion dynamics and operational issues Demonstration of capture technology and possible underground storage, pending suitable site identification and permitting

Planned demonstration projects Progressing from this lab- and pilot-scale program, a 250 MWe demonstration plant was envisaged as the final step-up before full commercial deployment. This was planned at the 3 GWe Ja¨nschwalde power plant in Germany, which consists of six 500 MWe generation blocks, each comprising two 650 MWth (250 MWe) conventional lignite-fired boilers driving a single steam turbine. It was planned to add one

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Table 4.9 Vattenfall AB-commissioned laboratory-scale test rigs for oxyfuel R&D Institute

Test rig

R&D objectives

Technical University of Hamburg-Hamburg, Germany Technical University of Dresden, Germany

20 kW combustion test rig with nonrecirculating oxyfuel combustion 50 kW recirculating oxyfuel test rig

Thermodynamics of oxyfuel process

Chalmers University of Technology, Gothenburg, Sweden

FGD operation on oxyfuel flue gas stream Combustor dynamics when shifting between oxygen and air firing Novel FGD processes 100 kW recirculating oxyfuel Oxyfuel combustion research test rig with wet and dry flue gas recirculation, assessing the changes in radiation and reaction kinetics under oxyfuel conditions 500 kW recirculating oxyfuel Drying and oxyfuel combustion test rig of lignite

Brandenburg Technical University (BTU), Germany Impact of recirculation Stuttgart University 20 kW combustion test rig conditions and staged Institute of Process with nonrecirculating combustion Engineering and Power oxyfuel combustion 500 kW recirculating oxyfuel Power plant system integration Plant Technology combustion test rig, with and combustion flame (IVD), Germany all power plant systems behavior

250 MWe oxyfuel boiler to one of the generation blocks, allowing demonstration of oxyfuel technology alongside conventional combustion. Feasibility studies began in the mid-2008, with construction planned to commence in 2011 and start-up scheduled for 2015. The overall RDD&D timeline was shown in Figure 1.11 and clearly illustrates the 20-year timescale required to bring these technologies to the stage of full commercial deployment. Unfortunately the Ja¨nschwalde demonstration was canceled in 2011. Fewer demonstration-scale and early deployment oxyfuel capture projects are being planned compared to pre- and post-combustion capture; a few that have been announced are summarized in Table 4.10.

4.5

Chemical looping systems

Chemical looping combustion is a form of oxyfueling in which oxygen is introduced to the combustion reactor via a metal oxide carrier (MexOy), which is either

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Table 4.10 Oxyfuel demonstration and early deployment projects Project; operator and partners

Project description

Korea CCS 2; KCRC

2018 500 MW coal-fired plant, with c. 2 Mt-CO2/year to saline aquifers or depleted gas fields 300 MW coal-fired plant, 2020 1 Mt-CO2/year for EOR in nearby fields

Daqing CCS; China Datang Corp. and Alstom White Rose; National Grid plc, Alstom UK Ltd.

Planned start-up

426 MW coal-fired plant, 2020, but project on hold due to 2 Mt-CO2/year to offshore saline cancellation of the UK CCS Demonstration competition aquifer or EOR storage

fully or partially reduced in the combustion reaction. The chemical looping concept is very flexible, and options have been demonstrated for full combustion, reforming to produce syngas, and for hydrogen production, either by reforming, WGS and CO2 removal, or indirectly during carrier regeneration. Chemical looping can also be applied to capture CO2, either in a postcombustion application or in gasification (pre-combustion) systems, where it can be used in combination with a chemical loop to provide oxygen to the gasifier.

4.5.1 Chemical looping combustion Considering methane as the fuel, chemical looping combustion proceeds according to the reaction: CH4ðgÞ 1 4Mex OyðsÞ ! 4Mex Oy
1ðsÞ 1 CO2ðgÞ 1 2H2 OðgÞ

(4.1)

This reaction can be applied either at high pressure in a gas turbine cycle or at atmospheric pressure in a steam cycle. After heat recovery from the off-gas, steam can be condensed out, leaving a high-purity CO2 stream for storage. Following this fuel oxidation step, the spent carrier is circulated out of the combustion reactor into a carrier reoxidation reactor and regenerated in the reaction: 4Mex Oy
1ðsÞ 1 2O2ðgÞ 24Mex OyðsÞ

(4.2)

This reoxidation captures oxygen directly from a supply of compressed air, eliminating the need for a separate ASU for oxygen supply. The overall chemical looping process is illustrated schematically in Figure 4.5. Oxides of the common transition metals (Fe, Cu, Ni, Mn, Ba) are possible carriers, with Fe2O3/Fe2O2, NiO/Ni, and BaO2/BaO being extensively studied. The fuel oxidation step may be exothermic (for Cu, Mn, or Ba carriers) or

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Fuel

CO2 H2O

Metal oxide reduction

Metal oxide

Metal Metal oxidation

Air

N2

Figure 4.5 Chemical looping combustion process.

Table 4.11 Chemical looping combustion using NiO carrier Process

Reaction

ΔH

Fuel oxidation

CH4 1 4NiO ! CO2 1 2H2 O 1 4Ni 1 Ni 1 O2 ! NiO 2

175 kJ/mol CH4

Regeneration

Fuel Metal oxide reduction

CO2 H2O Metal oxide

Metal

2489 kJ/mol O2

Cooling N2

Metal oxidation

CO2 H2O

Generator

Air Compression

Gas turbines

Figure 4.6 Chemical looping combustion applied in a gas turbine cycle.

endothermic (for Fe and Ni carriers), while the carrier reoxidation step is always exothermic, the total energy released in the overall process being the same as for the direct combustion of the fuel. Table 4.11 shows the reactions and energetics with NiO as the carrier. A schematic of chemical looping combustion applied in a gas turbine cycle is shown in Figure 4.6. The fuel oxidation reactor here replaces the conventional combustion chamber of the gas turbine, while the CO2 plus steam off-gas from the reoxidation reactor can also be expanded through a turbine to generate additional power. In development work to date, the metal oxide carrier is typically in the form of particles with a diameter of 100
500 μm, and in some cases (e.g., Ni) it is carried on an alumina support. The reactions take place in two fluidized bed reactors, which achieve efficient heat and mass transfer. The recycling of solid carrier between the two reactors is both an important control on the operating temperatures

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Table 4.12 Current RD&D areas in chemical looping combustion Research area

Description

Performance of mixed oxide Assessment of mixed carriers, such as Fe2O3
CuO, Ni
Ba, and Ni
La, with the aim of maximizing reactivity and carriers stability under cyclic operations. Adding a second metal can aid in the formation of easily reducible oxides of the primary carrier while improving carrier
support interaction in the case of supported oxides Chemical looping with Identification and evaluation of carriers which release oxygen oxygen uncoupling in the fuel reactor, allowing combustion in gaseous rather than bound oxygen Carrier material handling Development of systems for high-rate carrier transport, including interconnected high-pressure fluidized beds, and optimization for carrier rates, carrier
ash separation, and other operating parameters Supported carrier particles Exploiting the high-temperature stability of ceramic materials to improve carrier particles’ sinter resistance, by embedding metal nanoparticles into a ceramic matrix to create nanocomposite carrier particles Sulfur resistance of carrier The presence of sulfur, mainly as H2S in fuel streams derived and support from coal, can result in degradation of carrier performance due to the production of sulfides, both of the carrier metal and of the support, if present

and overall heat balance between the two reactors as well as being a major technological challenge. For example, the BaO2/BaO chemical loop requires 40 kg-BaO2/ kg-CH4, and applying this carrier to generate supercritical steam for a 500 MWe power plant requires a carrier transport rate of 1 kt/s (3.6 Mt/h), while also avoiding gas leakage between the reactors. Chemical looping combustion has been demonstrated in prototype facilities, at scales up to 1 MWth using various metal oxide carriers, and 6.5 MWth using CaO. Current areas of R&D focus are summarized in Table 4.12.

4.5.2 Chemical looping reforming A number of chemical looping configurations are possible that can generate syngas for liquids production or hydrogen for fuel cell and other uses. If the supply of metal oxide to the fuel oxidation reaction in Equation (4.1) is limited, partial oxidation of the fuel can be achieved, yielding a CO 1 H2 syngas: CH4ðgÞ 1 Mex OyðsÞ 2Mex Oy
1ðsÞ 1 COðgÞ 1 2H2ðgÞ

(4.3)

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Carbon Capture and Storage

For example, using NiO as carrier, the reactions would be as follows: Fuel partial oxidation CH4 1 NiO ! CO 1 2H2 1 Ni

(4.4)

Steam reforming CH4 1 H2 O ! CO 1 3H2

(4.5)

Regeneration Ni 1

1 O2 ! NiO 2

(4.6)

4.5.3 Chemical looping hydrogen production Several chemical looping variants have been demonstrated for pure hydrogen production. The example illustrated in Figure 4.7 shows hydrogen production in the carrier regeneration step, using Fe/Fe3O4/Fe2O3 as the carrier and water as the source of oxygen for regeneration. The process reactions for this concept are as follows: Fuel partial oxidation C1

1 O2 ! CO 2

(4.7)

Syngas oxidation CO 1 3Fe2 O3 ! CO2 1 2Fe3 O4

(4.8)

CO 1 Fe3 O4 ! CO2 1 3FeO

(4.9)

Fuel

Gasification

CO H2

Metal oxide reduction 2

Syngas

Fe3O4

Metal oxide reduction 2

CO2 H2O

H2 FeO

H2O

Air

Fe2O3 Metal oxidation 1

N2 Fe3O4

Metal oxidation 2

Figure 4.7 Chemical looping hydrogen production using FeO carrier.

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Carrier oxidation 3FeO 1 H2 O ! Fe3 O4 1 H2

(4.10)

Carrier combustion 4Fe3 O4 1 O2 ! 6Fe2 O3

(4.11)

The first gasification stage may be applied to the full range of carbon-based fuels. An advanced chemical looping system that uses two loops to generate H2 and CO2 streams in a coal gasification process has been demonstrated by Alstom Power. The chemical loops employed in the process are a CaS/CaSO4 loop to provide oxygen for syngas production from partial combustion of coal: Fuel partial oxidation 4C 1 CaSO4 ! 4CO 1 CaS

(4.12)

Carrier A oxidation CaS 1 2O2 ! CaSO4

(4.13)

and a CaO/CaCO3 loop to remove CO2 after water shifting CO: Water
gas shift CO 1 H2 O2CO2 1 H2

(4.14)

Carrier B carbonation CaO 1 CO2 ! CaCO3

(4.15)

Carrier B calcination CaCO3 1 heat ! CaO 1 CO2

(4.16)

This calcium chemical looping process is shown schematically in Figure 4.8.

4.6

Capture-ready and retrofit power plant

During the period of further development and demonstration of CCS technologies, and while the framework of regulations and incentives remains uncertain, there will be continued demand for the construction of new power generation plants, both to provide new capacity and to replace retiring units. If new-generation plants are

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Carbon Capture and Storage

H2

CO2

N2

CaCO3 CaS

CaO CaS

Inerts

Inerts

Air

Fuel Steam

Reducer

Calciner

Oxidizer

CaO CaSO4

CaCO3 Inerts

Figure 4.8 Calcium chemical looping hydrogen production process.

constructed without a capability to retrofit carbon capture, the operator may eventually need to either buy carbon credits to offset emissions (the so-called carbon lockin) or shut down the plant if the cost of carbon credits were to exceed the marginal cash flow per unit carbon emission. This risk can be mitigated by ensuring that the requirements for retrofitting carbon capture are considered in the plant design and construction, resulting in a capture-ready plant. In Europe, the package of energy measures agreed by the European Union Heads of Government at the 2007 Spring Energy Council recognized that CCS will be required on coal- and gas-fired generation plants to meet emissions reduction targets for 2020 and beyond. The European Union Commission has therefore proposed that all planning consents from 2010 onward will require that plants should be capture-ready, while CCS installation will be a requirement from 2020. The intention of the capture-ready requirement is to ensure that once they have been successfully demonstrated, capture technologies can be rapidly adopted to maximize the impact on cumulative emissions.

4.6.1 Capture-ready power plants To be considered as capture-ready, the retrofitting of capture systems should be both technically and economically feasible, although the latter requirement may be problematic to demonstrate at the planning stage in view of uncertainties in the future carbon market and cost of installation. The main technical factors to be considered in designing a capture-ready plant are summarized in Table 4.13, including specific considerations for pre-combustion, oxyfuel, and post-combustion capture. As noted in the table, each of the three capture options—pre- and postcombustion or oxyfueling—has specific requirements to ensure capture readiness, and the risk associated with pre-investment for capture readiness therefore differs between the options. These considerations are summarized in Table 4.14. In the case of oxyfueling, the risk that prohibitive additional requirements may emerge as the technology reaches full deployment can be mitigated by also considering the requirements for post-combustion capture when designing the plant for capture readiness, and carrying this option as a fallback.

Table 4.13 Technical factors for capture-ready power plant design Factor

Requirements

Space

Ensure space is available in the required location for additional or upgraded equipment and utilities (e.g., ASU for oxyfuel, WGS reactors for pre-combustion gasification, absorption towers for post-combustion capture; installation or upgrade of FGD, CO2 compression, possible makeup steam generation), as well as space required during construction and for maintenance access Plant capacity and Consider the energy penalty for capture when sizing the plant, depending flexibility on required net capacity Consider required load flexibility of both pre- and post-retrofit plant, and implications for plant design Utility capacity Ensure spare utility capacity or expansion capability for post-retrofit operation (e.g., electrical, control and instrumentation systems, fire and cooling water capacities, waste treatment) Capture process- Oxyfuel-ready; materials and design impact of higher combustion specific factors temperature; ensure minimum air leakage into boilers; power requirement for ASU Gasification pre-combustion capture-ready; integration of WGS reactor, H2-firing capability of gas turbines Post-combustion capture-ready; LP steam requirement for CO2 stripping; impact on steam turbine operation of reduced LP steam rate Physical Provision of tie-in points for new equipment and to existing utilities, integration process heat and cooling system Heat integration Consider both high- and low-grade heat requirements to ensure maximum efficiency of the post-retrofit plant (e.g., excess or expandable steam generation capacity) Operation Consider options to reduce the downtime incurred to install the retrofit and optimize plant operability post-retrofit CO2 storage Establish carbon storage options and requirements (e.g., access to new or existing CO2 transport infrastructure, geological or other storage site)

Table 4.14 Risks associated with capture-ready options Capture option

Captureready risk

Considerations

Post-combustion

Low

Oxyfuel combustion

Medium

Pre-combustion (IGCC plant)

Medium or high

Some viable technology options are already commercially deployed and requirements for these are well understood. Further developments may provide opportunities for easier retrofit at reduced costs, or for the use of new technologies Oxyfuel combustion has reached the demonstration scale but is not yet commercially deployed, and requirements are therefore not yet fully understood Higher base cost of IGCC relative to conventional pulverized coal plant and major plant impact of capture readiness means that the choice of IGCC over PC is currently a major pre-investment

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Carbon Capture and Storage

The largest recent new-build power plant that has been made capture-ready is the 1080 MW coal or biomass co-fired plant constructed by E.ON at Maasvlakte, Rotterdam in the Netherlands and commissioned in 2015. Post-combustion capture of up to 5.6 Mt-CO2/year could commence by 2020, with storage in depleted oil and gas fields under the North Sea.

4.6.2 Retrofitting capture capability In retrofitting carbon capture to existing power plants that have not been designed as capture-ready, all of the considerations in the previous section will have a bearing on the retrofit, and the feasibility and cost of installation will be specific to the design, age, and location of each individual plant. A key decision will be whether to accept the derating of the net power output of the plant, as a result of the energy cost of capture, or to add additional generation capacity to sustain the previous plant rating. Plant space and layout will be a limiting factor in some cases. The power derating impact of retrofitting post-combustion capture to a 500 MWe power plant is illustrated in Table 4.15 for a range of existing and future power plant efficiencies. The analysis assumes 96% capture efficiency using an amine stripping system with an energy penalty of 15% of the gross thermal power rating of the plant. Clearly, for less-efficient plant, the capital cost as well as the increased operating and maintenance cost of the post-retrofit plant, coupled with a B40% reduction in Table 4.15 Output and efficiency impact of post-combustion capture retrofit Plant type

Subcritical

Supercritical

Ultrasupercritical

Future

500 40% 0.79

500 50% 0.64

500 55% 0.58

188 38%

150 30%

136 27%

350 30% 0.039

364 40% 0.035

Plant parameters before post-combustion capture retrofit Net output (MWe) Efficiency CO2 emissions (t-C/MWh)

500 35% 0.91

Post-combustion capture penalties Capture energy penalty (MWe) Net output derating

215 43%

Plant parameters after post-combustion capture retrofit Net output (MWe) Efficiency CO2 emissions (t-C/MWh)

286 20% 0.055

313 25% 0.048

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Table 4.16 Retrofit capture projects in Electric Power Research Institute (EPRI) feasibility study Project; operator and partners

Plant capacity and type

Powerton; Midwest Generation, USA Coal Creek; Great River Energy, USA Intermountain; Intermountain Power, USA Lingan; Nova Scotia Power, Canada Bay Shore Unit 1; FirstEnergy, USA

1.5 GW subcritical pulverized coal plant 1.1 GW subcritical pulverized coal plant 1.8 GW subcritical pulverized coal plant 616 MW subcritical pulverized coal plant 129 MW petcoke-fueled CFB

net output if makeup power is not added, will result in a very substantial increase in the cost of electricity supply. The location of an existing plant in relation to potential storage sites will also be a major factor in determining the economic feasibility of retrofitting, in view of the cost of construction and operation of the required CO2 transportation infrastructure (see Chapter 23). The SaskPower operated Boundary Dam capture project (see Table 4.7) was the first commercial-scale capture retrofit to an existing power plant, while the NRG operated Petra Nova capture project is the largest currently operating at 1.6 MtCO2/year. Retrofit feasibility has also been studied for a number of other plants in the United States, as summarized in Table 4.16 (see Dillon et al., 2013). While the study concluded that retrofitting was technically feasible for all five plants, Intermountain was judged best suited due to the good baseline plant efficiency (35.6%), high capacity (1.8 GW) leading to economies of scale, availability of space for retrofit equipment, and various other plant characteristics including a steam supply well matched to post-combustion capture pressure needs and an existing FGD system.

4.7

Approaches to zero-emission power generation

In addition to the options described above, which essentially apply capture technologies to more or less conventional power generation systems, a number of alternative concepts have been proposed to achieve ZEP generation using various novel components.

4.7.1 AZEP concept: Norsk Hydro/Alstom The Advanced Zero Emission Power Plant (AZEP) concept was originally proposed by Norsk Hydro in 2002 and has been further developed by a consortium of companies including Alstom Power, Siemens, ENI Tecnologie, and Borsig. The AZEP concept, illustrated in Figure 4.9, is a Brayton-cycle gas turbine in which oxyfueled combustion of natural gas is achieved in a mixed conducting medium (MCM)

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Carbon Capture and Storage

Combustors

MCM reactor

Cooling water

Heat

O2

Bleed gas heat exchange

Heat

CO2 H2O

HRSG CO2

Natural gas

H2O

Generator

Air

Steam turbine

Oxygen-depleted air

Gas turbine

Figure 4.9 AZEP schematic flow scheme with dual-input HRSG.

membrane reactor. The underlying ion transport membrane technology is described in Chapter 8. High efficiency is achieved using an HRSG plus steam turbine bottoming cycle, shown here on a single drive shaft with the gas turbine. Heat from the MCM reactor combustion product stream is also recovered, either by driving an auxiliary CO2 and steam turbine or, as shown here, as a secondary heat input to the HRSG. Results from fabrication and initial testing of the MCM modules have achieved targets for the project, validated model predictions, and confirmed the feasibility of the AZEP concept. The test module was constructed from extruded square-channel monoliths, achieving a contact area . 500 m2/m3. Under AZEP process conditions the reactor is predicted to give an oxygen production rate of B37 mol-O2/s  m3 of module volume, equivalent to a gross power density of B15 MW/m3 of net MCM volume. Firm plans for a demonstration-scale plant have yet to be announced.

4.7.2 ZEC concept: Los Alamos National Laboratory The zero-emission coal (ZEC) concept was originally proposed by the Los Alamos National Laboratory and was further developed by the Zero Emission Coal Alliance (ZECA), later the Zeca Corporation. The ZEC concept integrates a number of advanced technologies: G

G

G

Coal gasification and steam methane reforming for hydrogen production Chemical looping (CaO2CaCO3 cycle) for CO2 removal from syngas Solid oxide fuel cells (SOFCs) for electricity production from hydrogen

As shown in Figure 4.10, the gasification step is also novel in that it starts with hydrogasification (i.e., reduction) rather than oxidation of the carbon-based fuel using a hydrogen slipstream.

Carbon capture from power generation

99

H 2O CH4 H2O Temp control

Gas cleanup

Gasification

H2O

Gas cleanup

CaCO3 Carbonation

H2

H2O Air

CO2 Fuel cell

Calcination

CO2 heat

CaO

Coal Ash

Sulfur and particulates

N2

H2 polishing CO2 compression

Figure 4.10 ZEC schematic flow scheme.

Table 4.17 Major reactions in the ZEC process Process

Reaction

Hydrogasification Steam methane reforming Carrier carbonation Fuel oxidation Carrier calcination

C 1 2H2 ! CH4 CH4 1 2H2 O ! CO2 1 4H2 CaO 1 CO2 ! CaCO3 2H2 1 O2 ! 2H2 O CaCO3 ! CaO 1 CO2

Since this reaction is exothermic (ΔH 5 274.9 kJ/mol), no external heat input is required for the gasification step, and injection of water can be used to control the gasifier reaction temperature. In the carbonation reactor, steam reforming of methane and carbonation of lime result in two reaction products: hydrogen and calcium carbonate. Hydrogen is oxidized in the SOFC, at an operating temperature of 1050 C, to produce electricity and steam. The latter feeds the steam reforming reaction, while additional heat recovered from the fuel cell is used to regenerate the CaO absorbent in the calcination reactor. The major reactions involved in the process are shown in Table 4.17. Laboratory-scale investigations of the hydrogasification and steam methane reforming reactions have been conducted under conditions representative of the ZEC concept and have achieved moderate to high conversion of bituminous coal to hydrogen. The final stage of the ZEC concept is the sequestration of CO2 by a mineral carbonation reaction with magnesium silicates (serpentine or olivine), as discussed in Chapter 10. The theoretical maximum efficiency of this process exceeds 90%, while accounting for heat losses and non-ideal fuel cell performance, an efficiency in excess of

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Carbon Capture and Storage

70% was considered achievable in practice. Compared to other generation processes, this extremely high efficiency would result in a substantially reduced quantity, and therefore cost, of CO2 to be disposed of per MWh generated. Unfortunately, despite its apparent promise, Zeca Corp. disappeared without trace shortly after it was recognized by Scientific American as the “Business Leader in Environmental Science” for 2003. Research work on similar systems, combining coal or biomass gasification, chemical looping combustion with CO2 capture and power generation using SOFCs is however being continued by a number of research groups (see, e.g., Aghaie et al., 2016).

4.8

References and resources

4.8.1 References Abanades, J.C., et al., 2015. Emerging CO2 capture systems. Int. J. Greenhouse Gas Control. 40, 126
166. Aghaie, M., Mehrpooya, M., Pourfayaz, F., 2016. Introducing an integrated chemical looping hydrogen production, inherent carbon capture and solid oxide fuel cell biomass fueled power plant process configuration. Energy Convers. Manage. 124, 141
154. Bailey, D.W., Feron, P.H.M., 2005. Post-combustion decarbonisation processes. Revue de l’Institut Franc¸ aise du Pe´ trole, Oil & Gas Science and Technology. 60, 461
474. Broutin, P., Kvamsdal, H., La Marca, C., van Os, P., Robinson, L., 2014. OCTAVIUS: a FP7 project demonstrating CO2 capture technologies. Energy Procedia. 63, 6194
6206. Buhre, B.J.P., et al., 2007. Oxy-fuel combustion technology for coal-fired power generation. Prog. Energy Combust. Sci. 31, 283
307. Damen, K., et al., 2014. Performance and modelling of the pre-combustion capture pilot plant at the Buggenum IGCC. Energy Procedia. 63, 6207
6214. Dillon, D., Wheeldon, J., Chu, R., Choi, G., Loy, C., 2013. A summary of EPRI’s engineering and economic studies of post combustion capture retrofit applied at various North American host sites. Energy Procedia. 37, 2349
2358. IEA GHG, 2000. Leading options for the capture of CO2 emissions at power stations. IEA Greenhouse Gas R&D Programme, Report PH3/14, Cheltenham, UK. Ishida, M., Jin, H., 1997. CO2 recovery in a power plant with chemical looping combustion. Energy Convers. Manage. 38 (Suppl.), S187
S192. Jansen, D., Gazzani, M., Manzolini, G., Van Dijk, E., Carbo, M., 2015. Pre-combustion CO2 capture. Int. J. Greenhouse Gas Control. 40, 167
187. Leung, D.Y.C., Caramanna, G., Maroto-Valer, M.M., 2014. An overview of current status of carbon dioxide capture and storage technologies. Renewable Sustainable Energy Rev. 39, 426
443. OECD/IEA, 2002. Solutions for the 21st Century, Zero Emissions Technologies for Fossil Fuels. OECD, Paris, France. Thimsen, D., et al., 2014. Results from MEA testing at the CO2 Technology Centre Mongstad. Part I: Post-combustion CO2 capture testing methodology. Energy Procedia. 63, 5938
5958.

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4.8.2 Resources CASTOR (European Union-funded project for post-combustion capture development and field trial): www.co2castor.com Chalmers University of Technology (chemical looping combustion): www.chalmers.se/en/ projects/Pages/kemcyklisk-forbranning.aspx ELCOGAS (pre-combustion capture pilot testing): www.elcogas.es/en/news-and-documents/ documents/presentations ENCAP (pre-combustion capture technology development project): www.encapco2.org European Technology Platform for Zero Emission Fossil Power Plant (ETP ZEP): www. zeroemissionsplatform.eu HTC Purenergy (modular post-combustion capture system with capacity of 1 kt-CO2/day): www.htcco2systems.com IEA GHG Oxyfuel Combustion Network: http://ieaghg.org/networks/oxy-fuel-combustionnetwork OCTAVIUS post-combustion demonstration project: www.octavius-co2.eu/ RWE (planned IGCC with CCS demonstration project): www.rwe.com/web/cms/en/2688/rwe/ innovation/projects-technologies/power-generation/fossil-fired-power-plants/igcc-ccs-powerplant Test Center Mongstad: www.tcmda.com/en US DOE National Carbon Capture Center: www.nationalcarboncapturecenter.com Vienna University of Technology (future energy technologies): www.vt.tuwien.ac.at/chemical_ process_engineering_and_energy_technology/future_energy_technology