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The Guidelines for National Greenhouse Gas Inventories, published in 2006 by the Intergovernmental Panel on Climate Change (IPCC), provides the procedure to calculate national GHGs emissions. However, it does not consider the net carbon dioxide emissions by the Portland cement clinker (released by the calcination process in the...
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... Studies have previously shown the costs of CO 2 capture through oxy-fuel combustion to be comparable to or lower than that of aminebased post-combustion CO 2 capture (Xu et al., 2007;Perrin et al., 2015;Lackner et al., 2022;Hu, 2011;Coskun et al., 2021). However, none of these studies include CO 2 purification to high-purity commercial CO 2 specifications. ...
CO2 capture, utilization, and storage is a key technology to mitigate the climate crisis, and the development of a CO2 infrastructure is critical for its future large-scale implementation. Successful deployment of a CO2 infrastructure depends largely on the compatibility between industry links, which is currently limited by unaligned CO2 purity specifications. Therefore, there is a need to understand the economic and technical implications of purity specifications throughout the whole value chain. This work presents, a highly detailed study encompassing the entire CO2 conditioning system, including compression, dehydration, liquefaction, and purification. A single, common CO2 conditioning system derived from operational facilities and designed for post-combustion CO2 feeds was applied for conditioning of four different feed gases. The investigation includes a techno-economic analysis considering capital and operational expenses for twelve different combinations of CO2 feed streams and outlet product specifications. The feed sources represent a range of CO2 purities from high purity to low purity and were derived from post-combustion, pre-combustion, and oxy-fuel combustion processes, while the considered product specifications include CO2 storage in depleted gas fields, saline aquifer, and utilization in the food industry. For the investigated systems, it is found that low-purity CO2 was the most expensive source gas to condition to commercial specifications due to a high content of non-condensable gases. The levelized costs for CO2 conditioning amounted to approximately 25 EUR/t CO2 , 27 EUR/t CO2 , 34 EUR/t CO2 , and 46 EUR/t CO2 for the investigated high purity, medium-high purity, medium-low purity, and low purity CO2 cases, respectively. In the investigated cases, only the specifications of low-volatile species were relevant. The impurity limit specifications were relatively close across the investigated commercial specifications, therefore, these did not show significant cost differences. The study clarifies the economic impact on the CO2 conditioning process from imposing equivalent purity constraints on CO2 from different sources.
... Validation of the proposed OPG system has been compared with similar studies in Figure 5. The considered systems for validation and comparison of the proposed system are those employed in Ghorbani et al, 21 Sanz et al (GC-B-J79), 42 Sanz et al (GC-AD-J79), 42 and Hu et al. 43 Ghorbani et al 21 proposed and analyzed a hybrid liquefied natural gas production system with pure oxygen, CO 2 capture and its liquefaction, and freshwater production through multi-effect desalination. Sanz et al 42 studied a near-term basic Graz cycle performance using the J79 turbine (GC-B-J79). ...
... Also, they focused on the advanced Graz cycle using the GE-J79 turbine (GC-B-J79). Hu et al 43 have been introduced an advanced evaporative gas turbine cycle with oxyfuel combustion for CO 2 capture with optimum operating values. As indicated in Figure 5, the proposed OPG system has the highest electrical efficiency in all similar works. ...
An innovative polygeneration structure is proposed based on the oxyfuel power generation (OPG) system integration with carbon dioxide (CO2) capture, CO2 power system, NH3/H2O absorption refrigeration (AR) unit, and organic Rankine power (ORP) cycle. In this regard, a combination of solid oxide electrolysis cell (SOEC) and solid oxide fuel cell (SOFC) is applied to produce the required pure oxygen for the OPG system. The proposed system simultaneously produces 7204 kmol/h hot water, 149.3 kmol/h liquid CO2, and 102.4 MW power in different cycles. Energy and exergy analyses are performed to evaluate the proposed system. The thermodynamic modeling and simulation of power and refrigeration cycles are performed in Aspen HYSYS software, and verified with high accuracy. Also, an integrated SOEC/SOFC simulation has been done using developed computer code in MATLAB programming. The overall electrical efficiency and the AR coefficient of performance are calculated at 31.55% and 0.4803, respectively. In addition, the thermal and exergy efficiencies of the proposed system are 65.10% and 70.60%, respectively. The exergy analysis indicates the combustion chamber's highest exergy destruction with a share of 35.26%. In the next rank, the heat exchangers (26.42%) and turbines (16.98%) have the largest share of degraded exergy among other devices. The sensitivity analysis demonstrates that when the oxygen productivity increases from 9050 to 9275 kg/h, the electrical efficiency in the total integrated structure and the liquid CO2 productivity rise to 34.57% and 6480 kg/h, respectively. Also, by increasing the natural gas entering the proposed structure from 2375 to 2550 kg/h, the exergy efficiency of the structure increases to 71.19% and its thermal efficiency decreases to 58.70%. A novel polygeneration system to produce power, liquid CO2, and heat is introduced. Integration of oxyfuel/ORC/CO2 power plants and absorption cooling unit is applied. A solid oxide fuel cell/electrolyzer technology is used to produce pure oxygen. The electrical and exergy efficiencies of the overall system are 31.55% and 70.60%. The exergy analysis indicates the combustion chamber has the highest exergy destruction.
... A detailed review of various separation technologies can be found in the literature (Abanades et al. 2015;Abu-Khader 2006;Gibbins and Chalmers 2008;Leung et al. 2014;Pires et al. 2011;Songolzadeh et al. 2014). Pre-combustion capture (Jansen et al. 2015;Scholes et al. 2010;Theo et al. 2016), oxyfuel process (Ferrari et al. 2017;Haryanto and Hong 2011;Hu 2011;Stanger et al. 2015;Sturgeon et al. 2009), postcombustion capture (Gupta et al. 2015;Thiruvenkatachari et al. 2009;Wang et al. 2017), and chemical looping (Coppola et al. 2012;Fan et al. 2012;Garc ıa et al. 2013;Li et al. 2017;Mantripragada and Rubin 2013;Wang et al. 2011) are the main approaches (Leung et al. 2014;Pires et al. 2011;Scholes et al. 2013) to separate carbon from the systems. Solvent scrubbing, cryogenic capture (Belaissaoui et al. 2012;Jensen et al. 2015;Li, Ding, et al. 2016;Song et al. 2018Song et al. , 2019Surovtseva et al. 2011), catalytic and membrane capture (Jansen et al. 2009;Kolster et al. 2017;Pera-Titus 2014;Thiruvenkatachari et al. 2009;Wang et al. 2018) methods are the major processes under the category of the post-combustion CO 2 capture technologies. ...
The solvent scrubbing method is one of the promising technologies to capture CO2 from
flue gas. In this technology, CO2 is absorbed from flue gas using a liquid solvent in an
absorption column and subsequently, solvent and CO2 are separated in a stripper column.
The recovered solvent from the stripper unit is recycled to an absorption unit along with
the makeup of the fresh solvent. Aqueous monoethanolamine (MEA) is widely used as the solvent in this method. The cost of solvent for continuous makeup in the absorber is one of
the major operating costs. The goal of this study is to minimize the flow rate of the MEA
stream to capture the specified amount of CO2 from flue gas to reduce the operating cost.
Various scenarios are simulated in commercial process plant simulator by varying the CO2 loading in lean MEA stream and absorber height. Flue gas compositions are obtained from the Rocky Mountain Hunter Power Plant (coal-fired), Utah, USA. We have shown that more than 80% CO2 is captured using absorber heights of 25–40 m and CO2 loading in MEA of 0.2 and less using the minimum flow rate of MEA. An insignificant amount of MEA (<0.2%) is lost from the absorption and stripper units. Other than the purchasing cost of the solvent, operating costs related to pumping, cooling, handling, etc. can be significantly reduced using the method developed in this study.
... A comparison between the electrical cycle efficiency in this paper with other case studies[65]. ...
In this paper, an integrated liquefied natural gas (LNG) production process, carbon dioxide separation and liquefaction, and fresh water production is proposed and analyzed. The hybrid system consists of three sections: power and heat generation by the process of combustion with pure oxygen, natural gas liquefaction with a two-stage refrigeration cycle (absorption refrigeration cycle and multi-component refrigerant), and multiple-effect distillation (MED) desalination. This integrated process produce 593.3 ton/h LNG, 84.62 ton/h carbon dioxide, and 74.58 ton/h fresh water. Exergy analysis shows that the highest exergy destruction is related to the shell and tube heat exchangers, which is about 38.8% and the lowest exergy destruction is related to the air coolers, 0.84%. Integrated process has an overall electrical efficiency (LHV Base) of 36.3%, a specific power of 0.179 kWh/kg LNG. Also the amount of energy consumed for producing carbon dioxide is 0.005 kWh/kg CO2, and gained output ratio (GOR) of 2.87 is achieved by three-stage MED desalination. A sensitivity analysis is done to investigate and identify the important parameters affecting the integrated process performance.
... The three leading technologies for CO 2 capture are post-combustion capture, precombustion capture at IGCC plants and oxy-fuel combustion Figure 1-5 shows a schematic of these CO 2 capture approaches (Hu, 2011). Typical CO 2 concentration in flue gas is 10-15%. ...
... However, further scale-up to a demonstration plant of over 100MW, integrated with CO 2 transport and storage is required before oxy-fuel combustion can be considered technologically ready for commercialisation. Additionally, in order to carry coal moisture as vapour at relatively low temperature and avoid the risk of explosion as well as the problem of corrosion, the primary recycle stream (Figure 1-7) must be dried and recycled after all flue gas cleaning units (Hu, 2011). Therefore, this method has a higher impact on the power plant process, where it complicates the operation and requires retrofitting existing plants because of the need for cold flue gas recycling which limits the combustion temperature (Kunze et al., 2012). ...
A rise of 2 oC in the Earth’s temperature is likely to occur when the concentration of CO2 in the atmosphere reaches approximately 450 ppm. CO2 emissions are closely related to the continual use of fossil fuels. In order to make fossil fuels sustainable, carbon capture & storage (CCS) is required to reduce CO2 emissions. There are three leading CO2 capture methods, namely post-combustion capture, oxy-fuel combustion and integrated gasification combined cycle (IGCC) pre-combustion capture. CO2 hydrate (CO2:6H2O) formation has been investigated as a way to capture CO2 in the IGCC conditions. The formation of hydrate in this work was experimentally investigated in an isochoric system (batch mode) inside a vertical fixed bed reactor (FBR), also known as high pressure volumetric analyser (HPVA). Standard silica gel with an average particle size of 200-500 µm, mean pore size of 5.14 nm, a pore volume of 0.64 cm3/g and a surface area of 499 m2/g was used as a porous medium. The presence of hydrate in FBR was justified by using graphic methods. The solubility of CO2 in water using Henry’s Law and the experimental pressure–time (P-t) curve were analysed to determine the formation of hydrate. Hydrate formation was confirmed when the mole fraction of CO2 dissolved in water exceeded the Henry’s Law value as well as a two-stage pressure drop in the experimental P-t curve. Initially, various sample preparation methods (methods 1, 2, 3 and 4) were studied leading to the selection of method 4 (the use of vigorous stirring) which had the highest moisture content (14.8 wt%) and the greatest water conversion to hydrate (40.5 mol%) at 275 K and 36 bar in a pure CO2 gas system. Also, high regeneration and repeatability of the results for all samples prepared by method 4 were expected as less water was occluded inside silica gel pores. Further investigations in pure CO2 gas systems highlighted the effect of type of silicas used, the importance of the type of promoters used, the concentration of promoters, experimental driving force, silica pore size, bed height and the amount of moisture content for formation of hydrate. Standard silica gel was the only silica found to show hydrate formation due to the best distribution of pore size. The high amount of bulk water inside zeolites 13X and spherical MCF-17 (21.3 and 50.8 wt% respectively) was the main reason of no hydrate formation observed. Additionally, the combined-promoters designated type T1-5 (0.01 mol% sodium dodecyl sulphate (SDS) + 5.6 mol% tetrahydrofuran (THF)) and type T3-2 (0.01 mol% SDS + 0.1 mol% tetra-butyl ammonium bromide (TBAB)) were the two best obtaining a CO2 uptake of 5.95 and 5.57 mmol of CO2 per g of H2O respectively. Ethylene glycol mono-ethyl ether (EGME; 0.1 mol%) was a good alternative to THF when combined with SDS (0.01 mol%) with a CO2 uptake of 5.45 mmol of CO2 per g of H2O for this combined-promoter designated type T1A-2. In addition, the CO2 uptake increased as ∆P increased or ∆T decreased. Moreover, mesoporous silica (silica gel) performed better than microporous silica (zeolite 13X) where the formation of hydrate by zeolite 13X was observed with minimal CO2 uptake (0.58 mmol of CO2 per g of H2O) when the bed height was reduced. Additionally, the total amount of CO2 consumed through hydrate formation increased as the amount of water inside mesoporous silica increased which was not the case for microporous silica. Furthermore, the experiments performed in the IGCC conditions (283 K and 70 bar) by employing T1-5 and T3-2 in a fuel gas mixture demonstrated low hydrate formation with a CO2 uptake of 1.5 and 1.1 mmol of CO2 per g of H2O respectively. This was expected due to the slow kinetics since CO2 molecules were competing with H2 molecules which also reduced the selectivity of CO2 molecules during hydrate formation. Hence, in reality, pure CO2 system is the best option for CCS through hydrate formation at the right operating conditions as compared to fuel gas mixture.
... After purification, the resulting CO 2 stream can be compressed for transport and stored in deep ocean, depleted oil/gas fields, un-mineable coal beds and deep saline reservoirs. CO 2 capture through combustion processes is based upon three main routes [3,4]. ...
... [48] Oxy-fuel combustion (option 2) RGibbs reactor model. Excess O 2 3% (mole) [49] O 2 /recycle CO 2 ratio 27% (mole) [49] Air Separation Unit Oxygen purity (molar): 0.995 [50] Chemical looping combustion (options 3 and 4) ...
... [48] Oxy-fuel combustion (option 2) RGibbs reactor model. Excess O 2 3% (mole) [49] O 2 /recycle CO 2 ratio 27% (mole) [49] Air Separation Unit Oxygen purity (molar): 0.995 [50] Chemical looping combustion (options 3 and 4) ...
A novel polygeneration process is presented in this paper that co-produces olefins, methanol, dimethyl ether, and electricity from conventional pipeline natural gas and different kinds of shale gases. Technical analyses of many variants of the process are performed, considering differences in power generation strategy and gas type. The technical analysis results show that the efficiency of the plant varies between 22%–57% (HHV) depending on the product portfolio. The efficiency is higher than a traditional methanol-to-olefin process, which enables it to be competitive with traditional naphtha cracking plants.
... 6−8 Oxyfuel combustion offers several advantages over air combustion: the furnace burns with higher flame temperature and therefore greater thermal efficiency; energy efficiency is increased because inert nitrogen is not heated in the furnace; flue gas volume is decreased by 75%; NO x emissions are nearly eliminated due to a greatly reduced nitrogen presence in the combustion stream; and postcombustion carbon dioxide capture is simplified because the flue gas is more than 90% carbon dioxide. 9 In order to make oxyfuel combustion in power plants economically feasible, an energyefficient and effective process for generating large amounts of relatively pure oxygen must be available. ...
Computational screening of metal-organic framework (MOF) materials for selective oxygen adsorption from air is used to identify new sorbents for the oxyfuel combustion process feedstock streams. A comprehensive study on the effect of MOF metal chemistry on gas binding energies in two common but structurally disparate metal-organic frameworks has been undertaken. Dispersion-corrected density functional theory methods were used to calculate the oxygen and nitrogen binding energies with each of fourteen metals, respectively, substituted into two MOF series, M2(dobdc) and M3(btc)2. The accuracy of DFT methods was validated by comparing trends in binding energy with experimental gas sorption measurements. A periodic trend in oxygen binding energies was found, with greater oxygen binding energies for early transition-metal-substituted MOFs compared to late transition metal MOFs; this was independent of MOF structural type. The larger binding energies were associated with oxygen binding in a side-on configuration to the metal, with concomitant lengthening of the O-O bond. In contrast, nitrogen binding energies were similar across the transition metal series, regardless of both MOF structural type and metal identity. Taken together, these findings suggest that early transition metal MOFs are best suited to separating oxygen from nitrogen, and that the MOF structural type is less important than the metal identity.
... The water stream and ash were removed at the bottom of the DCC column. Secondly, the CO 2 stream at 33 • C was compressed to around 3 MPa (30 bar) by a two-stage intercooled compressor (Hu, 2011). Thirdly, the CO 2 stream was fed to a temperature swing dual-bed adsorption dryer to meet the required level of dried CO 2 . ...
