Carbon dioxide storage capacity in uneconomic coal beds in Alberta,Canada: Methodology,potential and site identification

Methodology is presented for a first-order regional-scale estimation of CO₂ storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO₂ storage have been defined on the basis of groundwater depth and CO₂ phase at in situ conditions. The theoretical CO₂ storage capacity was estimated on the basis of CO₂ adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO₂/km² and 1260 kt CO₂/km², for a total of approximately 20 Gt CO₂. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO₂, and if all the coals will be accessed by CO₂. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO₂. Not all the effective CO₂ storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO₂/km², then the CO₂ storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO₂.     

Pulverized coal stream ignition delay under conventional and oxy-fuel combustion conditions

The coal stream ignition process is critical to the performance of modern pulverized coal burners, particularly when operating under novel conditions such as experienced in oxy-fuel combustion. However, experimental studies of coal stream ignition are lacking, and recent modeling efforts have had to rely on comparisons with a single set of experiments in vitiated air. To begin to address this shortfall, we have conducted experiments on the ignition properties of two U.S. and two Chinese coals in a laminar entrained flow reactor. Most of the measurements focused on varying the coal feed rate for furnace temperatures of 1230–1320 K and for 12–20 vol.% O₂ in nitrogen. The influence of coal feed rate on ignition with a carbon dioxide diluent was also measured for 20 vol.% O₂ at 1280 K. A second set of measurements was performed for ignition of a fixed coal feed rate in N₂ and CO₂ environments at identical furnace temperatures of 1200 K, 1340 K, and 1670 K. A scientific CCD camera equipped with a 431 nm imaging filter was used to interrogate the ignition process. Under most conditions, the ignition delay decreased with increasing coal feed rate until a minimum was reached at a feed rate corresponding to a particle number density of approximately 4 × 10⁹ m^?3 in the coal feed pipe. This ignition minimum corresponds to a cold flow group number, G, of ～0.3. At higher coal feed rates the ignition delay increased. The ignition delay time was shown to be very sensitive to (a) the temperature of the hot coflow into which the coal stream is introduced, and (b) the coal particle size. The three high volatile bituminous coals showed nearly identical ignition delay as a function of coal feed rate, whereas the subbituminous coal showed slightly greater apparent ignition delay. Bath gas CO₂ content was found to have a minor impact on ignition delay.     

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.     

Biofilm enhanced geologic sequestration of supercritical CO2

In order to develop subsurface CO₂ storage as a viable engineered mechanism to reduce the emission of CO₂ into the atmosphere, any potential leakage of injected supercritical CO₂ (SC-CO₂) from the deep subsurface to the atmosphere must be reduced. Here, we investigate the utility of biofilms, which are microorganism assemblages firmly attached to a surface, as a means of reducing the permeability of deep subsurface porous geological matrices under high pressure and in the presence of SC-CO₂, using a unique high pressure (8.9 MPa), moderate temperature (32 °C) flow reactor containing 40 millidarcy Berea sandstone cores. The flow reactor containing the sandstone core was inoculated with the biofilm forming organism Shewanella fridgidimarina. Electron microscopy of the rock core revealed substantial biofilm growth and accumulation under high-pressure conditions in the rock pore space which caused >95% reduction in core permeability. Permeability increased only slightly in response to SC-CO₂ challenges of up to 71 h and starvation for up to 363 h in length. Viable population assays of microorganisms in the effluent indicated survival of the cells following SC-CO₂ challenges and starvation, although S. fridgidimarina was succeeded by Bacillus mojavensis and Citrobacter sp. which were native in the core. These observations suggest that engineered biofilm barriers may be used to enhance the geologic sequestration of atmospheric CO₂.     

Coastal spreading of olivine to control atmospheric CO2 concentrations: A critical analysis of viability

Qualitative proposals to control atmospheric CO₂ concentrations by spreading crushed olivine rock along the Earth's coastlines, thereby accelerating weathering reactions, are presently attracting considerable attention. This paper provides a critical evaluation of the concept, demonstrating quantitatively whether or not it can contribute significantly to CO₂ sequestration. The feasibility of the concept depends on the rate of olivine dissolution, the sequestration capacity of the dominant reaction, and its CO₂ footprint. Kinetics calculations show that offsetting 30% of worldwide 1990 CO₂ emissions by beach weathering means distributing of 5.0 Gt of olivine per year. For mean seawater temperatures of 15–25 °C, olivine sand (300 μm grain size) takes 700–2100 years to reach the necessary steady state sequestration rate and is therefore of little practical value. To obtain useful, steady state CO₂ uptake rates within 15–20 years requires grain sizes <10 μm. However, the preparation and movement of the required material poses major economic, infrastructural and public health questions. We conclude that coastal spreading of olivine is not a viable method of CO₂ sequestration on the scale needed. The method certainly cannot replace CCS technologies as a means of controlling atmospheric CO₂ concentrations.     

Seismic detection of CO2 leakage along monitoring wellbores

A pilot carbon dioxide (CO₂) sequestration experiment was carried out in the Michigan Basin in which ～10,000 tonnes of supercritical CO₂ was injected into the Bass Island Dolomite (BILD) at 1050 m depth. A passive seismic monitoring (PSM) network was operated before, during and after the ～17-day injection period. The seismic monitoring network consisted of two arrays of eight, three-component sensors, deployed in two monitoring wells at only a few hundred meters from the injection point. 225 microseismic events were detected by the arrays. Of these, only one event was clearly an injection-induced microearthquake. It occurred during injection, approximately 100 m above the BILD formation. No events, down to the magnitude ?3 detection limit, occurred within the BILD formation during the injection. The observed seismic waveforms associated with the other 224 events were quite unusual in that they appear to contain dominantly compressional (P) but no (or extremely weak) shear (S) waves, indicating that they are not associated with shear slip on faults. The microseismic events were unusual in two other ways. First, almost all of the events occurred prior to the start of injection into the BILD formation. Second, hypocenters of the 94 locatable events cluster around the wells where the sensor arrays were deployed, not the injection well. While the temporal evolution of these events shows no correlation with the BILD injection, they do correlate with CO₂ injection for enhanced oil recovery (EOR) into the 1670 m deep Coral Reef formation that had been going on for ～2.5 years prior to the pilot injection experiment into the BILD formation. We conclude that the unusual microseismic events reflect degassing processes associated with leakage up and around the monitoring wells from the EOR-related CO₂ injection into the Coral Reef formation, ～700 m below the depth of the monitoring arrays. This conclusion is also supported by the observation that as soon as injection into the Coral Reef formation resumed at the conclusion of the BILD demonstration experiment, seismic events (essentially identical to the events associated with the Coral Reef injection prior to the BILD experiment) again started to occur close to a monitoring arrays. Taken together, these observations point to vertical migration around the casings of the monitoring wellbores. Detection of these unusual microseismic events was somewhat fortuitous in that the arrays were deployed at the depth where the CO₂ undergoes a strong volume increase during transition from a supercritical state to a gas. Given the large number of pre-existing wellbores that exist in depleted oil and gas reservoirs that might be considered for CO₂ sequestration projects, passive seismic monitoring systems could be deployed at appropriate depths to systematically detect and monitor leakage along them.     

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%.     

Experimental investigation of the CO2 sealing efficiency of caprocks

Using a combination of experimental (petrophysical and mineralogical) methods, the effects of high-pressure CO₂ exposure on fluid transport properties and mineralogical composition of two pelitic caprocks, a limestone and a clay-rich marl lithotype have been studied. Single and multiphase permeability tests, gas breakthrough and diffusion experiments were conducted under in situ p/T conditions on cylindrical plugs (28.5 mm diameter, 10–20 mm thickness).The capillary CO₂ sealing efficiency of the initially water-saturated sample plugs was found to decrease in repetitive gas breakthrough experiments on the same sample from 0.74 to 0.41 MPa for the limestone and from 0.64 to 0.43 MPa for the marl. Helium breakthrough experiments before and after the CO₂ tests showed a decrease in capillary threshold (snap-off) pressure from 1.81 to 0.62 MPa for the limestone.Repetitive CO₂ diffusion experiments on the marlstone revealed an increase in the effective diffusion coefficient from 7.8 × 10^?11 to 1.2 × 10^?10 m².Single-phase (water) permeability coefficients derived from steady-state permeability tests ranged between 7 and 56 nano-Darcy and showed a consistent increase after each CO₂ test cycle. Effective gas permeabilities were generally one order of magnitude lower than water permeabilities and exhibit the same trend. XRD measurements performed before and after exposure to CO₂ did not reveal any distinct change in the mineral composition for both samples. Similarly, no significant changes were observed in specific surface areas (determined by BET) and pore-size distributions (determined by mercury injection porosimetry). High-pressure CO₂ sorption experiments on powdered samples revealed significant CO₂ sorption capacities of 0.27 and 0.14 mmol/g for the marlstone and the limestone, respectively.The changes in transport parameters in the absence of detectable mineral alterations may be explained by carbonate dissolution and further precipitation along a pH profile across the sample plug which would not be subject to quantitative mineral alteration.     

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.     

Constraints on the in situ density of CO2 within the Utsira formation from time-lapse seafloor gravity measurements

At Sleipner, CO₂ is being separated from natural gas and injected into an underground saline aquifer for environmental purposes. Uncertainty in the aquifer temperature leads to uncertainty in the in situ density of CO₂. In this study, gravity measurements were made over the injection site in 2002 and 2005 on top of 30 concrete benchmarks on the seafloor in order to constrain the in situ CO₂ density. The gravity measurements have a repeatability of 4.3 μGal for 2003 and 3.5 μGal for 2005. The resulting time-lapse uncertainty is 5.3 μGal. Unexpected benchmark motions due to local sediment scouring contribute to the uncertainty. Forward gravity models are calculated based on both 3D seismic data and reservoir simulation models. The time-lapse gravity observations best fit a high temperature forward model based on the time-lapse 3D seismics, suggesting that the average in situ CO₂ density is about to 530 kg/m³. Uncertainty in determining the average density is estimated to be ±65 kg/m³ (95% confidence), however, this does not include uncertainties in the modeling. Additional seismic surveys and future gravity measurements will put better constraints on the CO₂ density and continue to map out the CO₂ flow.     

Natural analogue of the rise and dissolution of liquid CO2 in the ocean

The behavior of natural carbon dioxide (CO₂) droplets (8–10 mm in diameter) were observed in a seafloor hydrothermal system at the Okinawa Trough. The natural CO₂ droplet contain 95–98% of CO₂, 2–3% of H₂S, and other gas species. The ascending CO₂ droplets were tracked by a remotely operated vehicle (ROV), and depth, temperature, salinity, pH and partial pressure of CO₂ (pCO₂) in seawater near the CO₂ droplets were measured during droplet ascent by a conductivity-temperature-depth sensor (CTD) and in situ pH/pCO₂ sensor. The visual images of the rising CO₂ droplets were recorded with a high definition television camera on the ROV. A mapping survey (400 m × 400 m; 4 horizontal layers) revealed a dominant distribution of low pH area over the natural CO₂ venting site. The size and rise rate of CO₂ droplets decreased during their ascent in the water column from depths of 1424 to 679 m (a tracking interval of 745 m). The CO₂ droplets dissolved gradually to become small flakes of CO₂ hydrate while rising, and these ascending flakes were found to disappear at 679 m depth. Although a pH as low as 5 was detected just above the liquid CO₂ venting site on the seafloor, no detectable pH depression in the water column ambient to the rising CO₂ droplets was observed. The results of the pH mapping survey showed only localized pH depression over the CO₂ venting site.     

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.     

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.     

The potential for increased atmospheric CO2 emissions and accelerated consumption of deep geologic CO2 storage resources resulting from the large-scale deployment of a CCS-enabled unconventional fossil fuels industry in the U.S.

Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO₂) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO₂ storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO₂ from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO₂ capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO₂ emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO₂, in addition to storing potentially 900–5000 MtCO₂ in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO₂ emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO₂ stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO₂ storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO₂ storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation.     

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.     

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.     

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.     

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.     

Modeling the impacts of climate policy on the deployment of carbon dioxide capture and geologic storage across electric power regions in the United States

This paper summarizes the results of a first-of-its-kind holistic, integrated economic analysis of the potential role of carbon dioxide (CO₂) capture and storage (CCS) technologies across the regional segments of the United States (U.S.) electric power sector, over the time frame 2005–2045, in response to two hypothetical emissions control policies analyzed against two potential energy supply futures that include updated and substantially higher projected prices for natural gas. This paper's detailed analysis is made possible by combining two specialized models developed at Battelle: the Battelle CO₂-GIS to determine the regional capacity and cost of CO₂ transport and geologic storage; and the Battelle Carbon Management Electricity Model, an electric system optimal capacity expansion and dispatch model, to examine the investment and operation of electric power technologies with CCS against the background of other options. A key feature of this paper's analysis is an attempt to explicitly model the inherent heterogeneities that exist in both the nation's current and future electricity generation infrastructure and in its candidate deep geologic CO₂ storage formations. Overall, between 180 and 580 gigawatts (GW) of coal-fired integrated gasification combined cycle with CCS (IGCC + CCS) capacity is built by 2045 in these four scenarios, requiring between 12 and 41 gigatonnes of CO₂ (GtCO₂) storage in regional deep geologic reservoirs across the U.S. Nearly all of this CO₂ is from new IGCC + CCS systems, which start to deploy after 2025. Relatively little IGCC + CCS capacity is built before that time, primarily under unique niche opportunities. For the most part, CO₂ emissions prices will likely need to be sustained at over $20/tonne CO₂ before CCS begins to deploy on a large scale within the electric power sector. Within these broad national trends, a highly nuanced picture of CCS deployment across the U.S. emerges. Across the four scenarios studied here, power plant builders and operators within some North American Electric Reliability Council (NERC) regions do not employ any CCS while other regions build more than 100 GW of CCS-enabled generation capacity. One region sees as much as 50% of its geologic CO₂ storage reservoirs’ total theoretical capacity consumed by 2045, while most of the regions still have more than 90% of their potential storage capacity available to meet storage needs in the second half of the century and beyond. A detailed presentation of the results for power plant builds and operation in two key regions: ECAR in the Midwest and ERCOT in Texas, provides further insight into the diverse set of economic decisions that generate the national and aggregate regional results.     

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.