The challenge in understanding the corrosion mechanisms under oxyfuel combustion conditions

Basic research on the corrosive effect of flue gases has been performed at the BAM Federal Institute for Materials Research and Testing (Germany). Conditions at both high and low temperatures were simulated in specially designed experiments. Carburization occured in flue gases with high CO₂ content and temperatures higher than 500 °C. In SO₂ containing flue gases sulphur was detected in the oxide scale. At lower temperatures no corrosion was observed when gases with low humidity were investigated. Humidity higher than 1500 ppm was corrosive and all steels with Cr contents lower than 12% revealed corroded surfaces. At low temperatures below 10 °C a mixture of sulphuric and nitric acid condensed on metal surfaces. Acid condensation caused severe corrosion. Humidity, CO₂, O₂, and SO₂ contents are the important factors determining corrosion. Below 300 °C acid condensation is the primary reason for corrosion. Low humidity and low temperatures are conditions which can be expected in the CO₂ separation and treatment process. This work includes major conditions of the flue gas and CO₂ stream in CCS plants and CCS technology.     

Ash and deposit formation from oxy-coal combustion in a 100 kW test furnace

Ash deposition is still an unresolved problem when retrofitting existing air-fired coal power plants to oxy-fuel combustion. Experimental data are quite necessary for mechanism validation and model development. This work was designed to obtain laboratory combustor data on ash and deposits from oxy-coal combustion, and to explore the effects of oxy-firing on their formation. Two bituminous coals (Utah coal and Illinois coal) and one sub-bituminous coal (PRB coal) were burned on a down-fired combustor under both oxy- and air-firing. Two oxy-fired cases, i.e., 27 vol% O₂/73 vol% CO₂ and 32 vol% O₂/68 vol% CO₂, were selected to match the radiation flux and the adiabatic flame temperature of air combustion, respectively. Once-through CO₂ was used to simulate fully cleaned recycled flue gas. The flue gas excess oxygen was fixed at 3 vol%. For each case, both size-segregated fly ash and bulk fly ash samples were obtained. Simultaneously, ash deposits were collected on an especially designed un-cooled deposition probe. Ash particle size distributions and chemical composition of all samples were characterized. Data showed that oxy-firing had insignificant impacts on the tri-modal ash particle size distributions and composition size distributions in the size range studied. Bulk ash compositions also showed no significant differences between oxy- and air-firing, except for slightly higher sulfur contents in some oxy-fired ashes. The oxy-fired deposits were thicker than those from air-firing, suggesting enhanced ash deposition rates in oxy-firing. Oxy-firing also had apparent impacts on the deposit composition, especially for those components (e.g., CaO, Fe₂O₃, SO₃, etc.) that could contribute significantly to ash deposition. Based on these results, aerodynamic changes in gas flow and changes in combustion temperature seemed more important than chemical changes of ash particles in determining deposit behavior during oxy-coal combustion.     

Flue gas desulphurization for hot recycle Oxyfuel combustion: Experiences from the 30 MWth Oxyfuel pilot plant in Schwarze Pumpe

Significant differences exist in the flue gas composition in hot recycle Oxyfuel conditions as e.g. the high CO₂ partial pressure (>90 vol%, dry), the very high SO₂ concentration and the high water content (approx. 30 vol%). Therefore certain design and operation criteria have to be observed for the flue gas desulphurization with forced oxidation under Oxyfuel combustion conditions. Several performance tests have been executed at the 30 MW_th Oxyfuel pilot plant in Schwarze Pumpe to evaluate the main performance parameters and to assess the influence of the major operation parameters. The results show that there are no fundamental problems for the operation of the flue gas desulphurization unit under Oxyfuel combustion conditions. High removal rates could be reached and no negative impact of the high CO₂ partial pressure was observed under the tested operating conditions. No major differences in the gypsum quality have been observed between air firing and Oxyfuel conditions.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

The oxyfuel process is one of the most promising options to capture CO₂ from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO₂ on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO₂ stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO₂ stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO₂ purity for capture and storage.     

Oxy-fuel coal combustion—A review of the current state-of-the-art

Carbon dioxide emissions will continue being a major environmental concern due to the fact that coal will remain a major fossil-fuel energy resource for the next few decades. To meet future targets for the reduction of greenhouse gas (GHG) emissions, capture and storage of CO₂ is required. Carbon capture and storage technologies that are currently the focus of research centres and industry include: pre-combustion capture, post-combustion capture, and oxy-fuel combustion. This review deals with the oxy-fuel coal combustion process, primarily focusing on pulverised coal (PC) combustion, and its related research and development topics. In addition, research results related to oxy-fuel combustion in a circulating fluidised bed (CFB) will be briefly dealt with.During oxy-fuel combustion, a combination of oxygen, with a purity of more than 95 vol.%, and recycled flue gas (RFG) referred to as oxidant is used for combusting the fuel producing a gas consisting of mainly CO₂ and water vapour, which after purification and compression, is ready for storage. The high oxygen demand is supplied by a cryogenic air separation process, which is the only commercially available mature technology. The separation of oxygen from air as well as the purification and liquefaction of the CO₂-enriched flue gas consumes significant auxiliary power. Therefore, the overall net efficiency is expected to be decreased by 8–12% points, corresponding to a 21–35% increase in fuel consumption. Alternatively, ion transport membranes (ITMs) are proposed for oxygen separation, which might be more energy efficient. However, since ITMs are far away from becoming a mature technology, it is widely expected that cryogenic air separation will be the selected technology in the near future. Oxygen combustion is associated with higher temperatures compared with conventional air combustion. Both fuel properties as well as limitations of steam and metal temperatures of the various heat exchanger sections of the boiler require a moderation of the temperatures in the combustion zone and in the heat-transfer sections. This moderation in temperature is accomplished by means of recycled flue gas. The interdependencies between the fuel properties, the amount and temperature of the recycled flue gas, and the resulting oxygen concentration in the combustion atmosphere are reviewed.The different gas atmosphere resulting from oxy-fuel combustion gives rise to various questions related to firing, in particular, with respect to the combustion mechanism, pollutant reduction, the risk of corrosion, and the properties of the fly ash or its resulting deposits. In this review, detailed nitrogen and sulphur chemistry was investigated in a laboratory-scale facility under oxy-fuel combustion conditions. Oxidant staging succeeded in reducing NO formation with effectiveness comparable to that typically observed in conventional air combustion. With regard to sulphur, a considerable increase in the SO₂ concentration was measured, as expected. However, the H₂S concentration in the combustion atmosphere in the near-flame zone increased as well. Further results were obtained in a pilot-scale test facility, whereby acid dew points were measured and deposition probes were exposed to the combustion environment. Slagging, fouling and corrosion issues have so far been addressed via short-term exposure and require further investigation.Modelling of PC combustion processes by computational fluid dynamics (CFD) has become state-of-the-art for conventional air combustion. Nevertheless, the application of these models for oxy-fuel combustion conditions needs adaptation since the combustion chemistry and radiative heat transfer is altered due to the different combustion gas atmosphere.CFB technology can be considered mature for conventional air combustion. In addition to its inherent advantages like good environmental performance and fuel flexibility, it offers the possibility of additional heat exchanger arrangements in the solid recirculation system, i.e. the ability to control combustion temperatures despite relatively low flue gas recycle ratios even when combusting in the presence of high oxygen concentrations.     

Effect of gas composition in Chemical-Looping Combustion with copper-based oxygen carriers: Fate of sulphur

Chemical-Looping Combustion (CLC) is an emerging technology for CO₂ capture because separation of this gas from the other flue gas components is inherent to the process and thus no energy is expended for the separation. Natural or refinery gas can be used as gaseous fuels and they may contain different amounts of sulphur compounds, such as H₂S and COS. This paper presents the combustion results obtained with a Cu-based oxygen carrier using mixtures of CH₄ and H₂S as fuel. The influence of H₂S concentration on the gas product distribution and combustion efficiency, sulphur splitting between the fuel reactor (FR) and the air reactor (AR), oxygen carrier deactivation and material agglomeration was investigated in a continuous CLC plant (500 W_th). The oxygen carrier to fuel ratio, ?, was the main operating parameter affecting the CLC system. Complete fuel combustion were reached at 1073 K working at ? values ≥1.5. The presence of H₂S did not produce a decrease in the combustion efficiency even when working with a fuel containing 1300 vppm H₂S. At these conditions, the great majority of the sulphur fed into the system was released in the gas outlet of the FR as SO₂, affecting to the quality of the CO₂ produced. Formation of copper sulphide, Cu₂S, and the subsequent reactivity loss was only detected working at low values of ? ≤ 1.5, although this fact did not produce any agglomeration problem in the fluidized beds. In addition, the oxygen carrier was fully regenerated in a H₂S-free environment. It can be concluded that Cu-based oxygen carriers are adequate materials to be used in a CLC process using fuels containing H₂S although quality of the CO₂ produced is affected.     

Kinetics of sulfur dioxide- and oxygen-induced degradation of aqueous monoethanolamine solution during CO2 absorption from power plant flue gas streams

Studies of the kinetics of sulfur dioxide (SO₂)- and oxygen (O₂)-induced degradation of aqueous monoethanolamine (MEA) during the absorption of carbon dioxide (CO₂) from flue gases derived from coal- or natural gas-fired power plants were conducted as a function of temperature and the liquid phase concentrations of MEA, O₂, SO₂ and CO₂. The kinetic data were based on the initial rate which shows the propensity for amine degradation and obtained under a range of conditions typical of the CO₂ absorption process (3–7 kmol/m³ MEA, 6% O₂, 0–196 ppm SO₂, 0–0.55 CO₂ loading, and 328–393 K temperature). The results showed that an increase in temperature and the concentrations of MEA, O₂ and SO₂ resulted in a higher MEA degradation rate. An increase in CO₂ concentration gave the opposite effect. A semi-empirical model based on the initial rate, ?r_MEA = {6.74 × 10⁹ e^?(29,403/RT)[MEA]^0.02([O]^2.91 + [SO₂]^3.52)}/{1 + 1.18[CO₂]^0.18} was developed to fit the experimental data. With the higher order of reaction, SO₂ has a higher propensity to cause MEA to degrade than O₂. Unlike previous models, this model shows an improvement in that any of the parameters (i.e. O₂, SO₂, and CO₂) can be removed without affecting the usability of the model.     

Effect of gas composition in Chemical-Looping Combustion with copper-based oxygen carriers: Fate of light hydrocarbons

Chemical-Looping Combustion (CLC) is an emerging technology for CO₂ capture because separation of this gas from the other flue gas components is inherent to the process and thus no energy is expended for the separation. Natural or refinery gas can be used as gaseous fuels and they may contain different amounts of light hydrocarbons. This paper presents the combustion results obtained with a Cu-based oxygen carrier using mixtures of CH₄ and light hydrocarbons (LHC) (C₂H₆ and C₃H₈) as fuel. The effect on combustion efficiency of the fuel reactor temperature, solid circulation flow rate and gas composition was studied in a continuous CLC plant (500 W_th). Full combustions were reached at 1073 and 1153 K working at oxygen to fuel ratios, ? higher than 1.5 and 1.2 respectively. Unburnt hydrocarbons were never detected at any experimental conditions at the fuel reactor outlet. Carbon formation can be avoided working at 1153 K or at ? values higher than 1.5 at 1073 K. After 30 h of continuous operation, the oxygen carrier exhibited an adequate behavior regarding attrition and agglomeration. It can be concluded that no special measures should be taken in a CLC process with Cu-based OC with respect to the presence of LHC in the fuel gas.     

Capture of carbon dioxide from flue or fuel gas mixtures by clathrate crystallization in a silica gel column

A column of silica gel was employed to contact water with flue gas (CO₂/N₂) mixture to assess if CO₂ can be separated by hydrate crystallization. Three different silica gels were used. One with a pore size of 30 nm (particle size 40–75 μm) and two with a pore size of 100 nm and particle sizes of 40–75 and 75–200 μm respectively. The observed trends indicate that larger pores and particle size increase the gas consumption, CO₂ recovery, separation factor and water conversion to hydrate. Thus, the gel (gel #3) with the larger particle size and larger pore size was chosen to carry out experiments with concentrated CO₂ mixtures and for experiments in the presence of tetrahydrofuran (THF), which itself is a hydrate forming substance. Addition of THF reduces the operating pressure in the crystallizer but it also reduces the gas uptake. Gel #3 was also used in experiments with a fuel gas (CO₂/H₂) mixture in order to recover CO₂ and H₂. It was found that the gel column performs as well as a stirred reactor in separating the gas components from both flue gas and fuel gas mixtures. However, the crystallization rate and hydrate yield are considerably enhanced in the former. Finally the need for stirring is eliminated with the gel column which is enormously beneficial economically.     

CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO₂ from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO₂ capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO₂ removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO₂, which is 23% lower than the base case of 3.9 GJ/ton CO₂. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.     

Characterization of a limestone in a batch fluidized bed reactor for sulfur retention under oxy-fuel operating conditions

CO₂ and SO₂ are some of the main polluting gases emitted into atmosphere in combustion processes using fossil fuel for energy production. The former is one of the major contributors to build-up the greenhouse effect implicated in global climate change and the latter produces acid rain. Oxy-fuel combustion is a technology, which consists in burning the fuel with a mix of pure O₂ and recirculated CO₂. With this technology the CO₂ concentration in the flue gas may be enriched up to 95%, becoming possible an easy CO₂ recovery. In addition, oxy-fuel combustion in fluidized beds allows in situ desulfurization of combustion gases by supplying calcium based sorbent.In this work, the effect of the principal operation variables affecting the sulfation reaction rate in fluidized bed reactors (temperature, CO₂ partial pressure, SO₂ concentration and particle size) under typical oxy-fuel combustion conditions have been analyzed in a batch fluidized bed reactor using a limestone as sorbent. It has been observed that sulfur retention can be carried out by direct sulfation of the CaCO₃ or by sulfation of the CaO (indirect sulfation) formed by CaCO₃ calcination. Direct sulfation and indirect sulfation operating conditions depended on the temperature and CO₂ partial pressure. The rate of direct sulfation rose with temperature and the rate of indirect sulfation for long reaction times decreased with temperature. An increase in the CO₂ partial pressure had a negative influence on the sulfation conversion reached by the limestone due to a higher temperature was needed to work in conditions of indirect sulfation. Thus, it is expected that the optimum temperature for sulfur retention in oxy-fuel combustion in fluidized bed reactors be about 925–950 °C. Sulfation reaction rate rose with decreasing sorbent particle size and increasing SO₂ concentration.     

CO2 removal using membrane gas absorption

The objective of this study is to investigate the potential process for the removal of carbon dioxide (CO₂) from flue gas using fundamental membrane contactor, which is a membrane gas absorption (MGA) system. The experiments consisted of microporous polyvinylidenefluoride (PVDF) flat sheet membrane with 0.1 μm (as module I) and 0.45 μm (as module II) pore size. 2-Amino-2-methyl-1-propanol (AMP) solution was employed as the liquid absorbent. The effect of AMP concentration was studied with variation in the range 1–5 M. In addition, the experiments were carried out with 10%, 20%, 30% and 40% gas ratio of CO₂ to N₂ and pure CO₂ as well. Through contact angle measurement, membranes for module I and module II were obtained with CA values of around 130.25° and 127.77°, respectively. The mass transfer coefficients for module II are lower than those of module I for 1–5 M of AMP. Furthermore, the increase in CO₂ concentration in the feed gas stream enhanced the CO₂ flux as the driving force of the system was increased in sequence from 1 M to 5 M of AMP. However, after the particular percentage (40%) of CO₂ inlet concentration, the CO₂ fluxes seem saturated. The combination of AMP as liquid absorbent and PVDF microporous membrane in MGA system has shown the potential to remove the CO₂ from flue gas. In addition, the higher AMP concentration gave higher mass transfer coefficient at low liquid flow rates.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

CO2 capture from hot stove gas in steel making process

The capture of CO₂ from a hot stove gas in steel making process containing 30 vol% CO₂ by chemical absorption in a rotating packed bed (RPB) was studied. The RPB had an inner diameter of 7.6 cm, an outer diameter of 16 cm, and a height of 2 cm. The aqueous solutions containing 30 wt% of single and mixed monoethanolamine (MEA), 2-(2-aminoethylamino)ethanol (AEEA), and piperazine (PZ) were used. The CO₂ capture efficiency was found to increase with increasing temperature in a range of 303–333 K. It was also found to be more dependent on gas and liquid flow rates but less dependent on rotating speed when the speed was higher than 700 rpm. The obtained results indicated that the mixed alkanolamine solutions containing PZ were more effective than the single alkanolamine solutions. This was attributed to the highest reaction rate of PZ with CO₂. A higher portion of PZ in the mixture was more favorable to CO₂ capture. The highest gas flow rates allowed to achieve a desired CO₂ capture efficiency and the correspondent height of transfer unit (HTU) were determined at different aqueous solution flow rates. Because all the 30 wt% single and mixed alkanolamine solutions could result in a HTU less than 5.0 cm at a liquid flow rate of 100 mL/min, chemical absorption in a RPB instead of a packed bed adsorber is therefore suggested to capture CO₂ from the flue gases in steel making processes.     

Reduction of CaSO4 oxygen carrier with coal in chemical-looping combustion: Effects of temperature and gasification intermediate

Chemical-looping combustion (CLC) has been suggested as an energy efficient method for the capture of carbon dioxide from combustion. Thermodynamics and kinetics of CaSO₄ reduction with coal via gasification intermediate in a CLC process were discussed in the paper, with respect to the CO₂ generating efficiency, the environmental factor and the surface morphology of oxygen carrier. Tests on the combined process of coal gasification and CaSO₄ reduction with coal syngas were conducted in a batch fluidized bed reactor at different reaction temperatures and with different gasification intermediates. The products were characterized by gas chromatograph, gas analyzers and scanning electron microscope. And the results showed that an increase in the reaction temperature aggravated the SO₂ emission. The CO₂ generating efficiency also increased with the temperature, but it decreased when the temperature exceeded 950 °C due to the sintering of oxygen carrier particles. The use of CO₂ as gasification intermediate in the fuel reactor had a positive effect on the sintering-resistant of oxygen carrier particles. However, increasing the steam/CO₂ ratio in gasification intermediate evidently enhanced CO₂ generating efficiency and reduced SO₂ environmental impact.     

The modelling of a hybrid combined cycle with pressurised fluidised bed combustion and CO2 capture

This study investigates the possibility of capturing CO₂ from flue gas under pressurised conditions, which could prove to be beneficial in comparison to working under atmospheric conditions. Simulations of two hybrid combined cycles with pressurised fluidised bed combustion and CO₂ capture are presented. CO₂ is captured from pressurised flue gas by means of chemical absorption after the boiler but before expansion. The results show a CO₂ capture penalty of approximately 8 percentage points (including 90% CO₂ capture rate and compression to 110 bar), which makes the efficiency for the best performing cycle 43.9%. It is 5.2 percentage points higher than the most probable alternative, i.e. using a natural gas fired combined cycle and a pulverised coal fired condensing plant separately with the same fuel split ratio. The largest part of the penalty is associated with the lower mass flow of flue gas after CO₂ capture, which leads to a decrease in work output in the expander and potential for feed water heating. The penalty caused by the regeneration of absorbent is quite low, since the high pressure permits the use of potassium carbonate, which requires less regeneration heat than for example the more commonly proposed monoethanolamine. Although the efficiencies of the cycles look promising it will be important to perform a cost estimate to be able to make a fair comparison with other systems. Such a cost estimate has not been done in this study. A significant drawback of these hybrid cycles in that respect is the complex nature of the systems that will have a negative effect on the economy.     

Parametric investigation of the calcium looping process for CO2 capture in a 10 kWth dual fluidized bed

Calcium looping (CaL) is a promising post-combustion CO₂ capture technology which is carried out in a dual fluidized bed (DFB) system with continuous looping of CaO, the CO₂ carrier, between two beds. The system consists of a carbonator, where flue gas CO₂ is adsorbed by CaO and a regenerator, where captured CO₂ is released. The CO₂-rich regenerator flue gas can be sequestered after gas processing and compression. A parametric study was conducted on the 10 kW_th DFB facility at the University of Stuttgart, which consists of a bubbling fluidized bed carbonator and a riser regenerator. The effect of the following parameters on CO₂ capture efficiency was investigated: carbonator space time, carbonator temperature and calcium looping ratio. The active space time in the carbonator, which is a function of the space time and the calcium looping ratio, was found to strongly correlate with the CO₂ capture efficiency. BET and BJH techniques provided surface area and pore volume distribution data, respectively, for collected sorbent samples. The rate of sorbent attrition was found to be 2 wt.%/h which is below the expected sorbent make-up rate required to maintain sufficient sorbent activity. Steady-state CO₂ capture efficiencies greater than 90% were achieved for different combinations of operational parameters. Moreover, the experimental results obtained were briefly compared with results derived from reactor modeling studies. Finally, the implications of the experimental results with respect to commercialization of the CaL process have been assessed.     

Gas conditioning—The interface between CO2 capture and transport

Gas conditioning is commonly referred to as the required processing for a produced natural gas to achieve transport and sales specifications. In this paper, gas conditioning as the processing required in the interface between CO₂ capture and transport is studied for nine different natural gas fired power plant concepts and three different CO₂ transport processes. Conditioning processes for both pipeline and ship transport are described and an enhanced process for volatile removal is developed. The energy requirement for the conditioning processes is normally between 90 and 120 kWh/tonne CO₂; however, this depends on the pressure and composition of the captured CO₂-rich stream. The loss of CO₂ in the water purge is small for most capture processes. The waste streams from the gas conditioning processes can contain large amounts of CO₂ and should therefore be further processed or reintroduced at an appropriate point upstream in the capture or gas conditioning process if possible. The integration benefit may vary depending on the composition of the CO₂-rich stream. It could be particularly interesting for processes with “innovative reactors” (membranes, sorbents, chemical looping) to integrate CO₂ capture and gas conditioning.     

Maintaining a neutral water balance in a 450 MWe NGCC-CCS power system with post-combustion carbon dioxide capture aimed at offshore operation

A post-combustion CO₂ capture process intended for offshore operations has been designed and optimised for integration with a natural gas-fired power plant on board a floating structure developed by the Norway-based company Sevan Marine ASA—designated Sevan GTW (gas-to-wire). The concept is constrained by the structure of the floater carrying a SIEMENS modular power system rated at 450 MW_e, with a capture rate of 90% and CO₂ compression (1.47 Mtpa) for pipeline pressure at 12 MPa. A net efficiency of 45% (based on a lower heating value) is estimated for the system with CO₂ capture, thus suggesting that the post-combustion CO₂ capture system is accountable for a fuel penalty of nine percentage points.The rationale behind the technology selection is the urgency of replacing the dispersed aero-derivative gas turbines which power the offshore oil and gas production units in Norwegian waters with near-zero emission power.As (inherently) fresh water usually constitutes a limiting factor in sea operations, efforts are made to obtain a neutral water balance to obtain an optimal design. This is primarily achieved by controlling the cleaned flue gas temperature at the top of the absorber column.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.