Near-Zero Emissions Oxy-Combustion Flue Gas Purification

Shah, Minish; Degenstein, Nich; Zanfir, M.; Solunke, Rahul; Kumar, Ravi; Bugayong, Jennifer; Burgers, Ken

doi:10.2172/1054517

Cited by 4 publications

(3 citation statements)

References 34 publications

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“…Species found in an oxy-combustion flue gas stream include primary components such as CO 2 , O 2 , N 2 , and Ar (Fogash 2010), as well as residual components such as SO 2 , SO 3 , nitrogen oxides, and HCl. Several technologies have seen laboratory-scale development for CPU service (Price et al 2009;Fogash 2010;Shah et al 2012;Perrin et al 2013;Follett 2017). Some of these technologies have also been tested on flue gas from commercial oxy-combustion demonstrations, with one demonstration having processed in the range of 4,000 m 3 /hr of feed gas (Lockwood 2014).…”

Section: The Potential For So 2 Recycling In Psc Servicementioning

confidence: 99%

The Ni-converter – an historic perspective

Rozelle¹,

Sridhar

Queneau

et al. 2018

Mineral Processing and Extractive Metallurgy

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Section: The Potential For So 2 Recycling In Psc Servicementioning

confidence: 99%

The Ni-converter – an historic perspective

Rozelle¹,

Sridhar

Queneau

et al. 2018

Mineral Processing and Extractive Metallurgy

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“…It is a general consensus that flue gas emissions derived from coal- and natural gas-fired power plants pose serious environmental and health concerns . In particular, sulfur oxides (SO x ) and nitrogen oxides (NO x ) are regarded as the most toxic gases emitted into the atmosphere during the combustion of fossil fuels while carbon dioxide (CO 2 ) is the major contributor to climate change. , At present, a wide variety of technological options have been commercialized or proposed to capture these acidic gaseous impurities. − The current state-of-the-art technologies for SO x and NO x removal include flue gas desulfurization (FGD) and selective catalytic reduction (SCR), respectively, which are placed upstream of the power plant, followed by a CO 2 capture unit (amine scrubbing) in a sequential, stepwise fashion as demonstrated in Figure . These conventional processes are often multi-step and complex, which require large land space with high capital cost. ,− Furthermore, they suffer from a variety of operational problems such as equipment fouling and corrosion, solvent losses, liquid channeling, flooding, and unwanted foaming.…”

Section: Introductionmentioning

confidence: 99%

Combined Flue Gas Cleanup Process for Simultaneous Removal of SO_x, NO_x, and CO₂—A Techno-Economic Analysis

et al. 2017

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Flue gas cleanup often requires the removal of SO x , NO x , and CO 2 in separate units before being emitted into the atmosphere. This stepwise treatment process incurs significant cost and energy penalty to the electricity production. A combined adsorption process based on pressure swing adsorption (PSA) by which these impurities are removed is envisioned as an efficient means of flue gas cleanup that can be applied relatively easily. In this study, the technological and economic feasibilities of a combined separation process in which SO x , NO x , and CO 2 are simultaneously removed from flue gas streams are assessed. Capital and operating costs are estimated based on sizing the equipment items and utilities needed, and the potentials for increased energy efficiency are determined in relation to the required PSA performance. The energy saving potential for the adoption of 2-bed and 4-bed PSA cycles is compared with conventional FGD, SCR, and amine scrubbing units needed to clean up flue gas in a stepwise fashion. The results show that energy savings can be expected when the PSA removal efficiency is greater than 90%. In the case of a 550 MW coal-fired power plant, the proposed system will impose an energy penalty of 24% to the cost of electricity, which is lower than that of current individual treatment units associated with SO x , NO x , and CO 2 removal. This energy penalty corresponds to a cleanup cost of $57/ton of all impurities captured for a 2-bed, four-step PSA process with a cycle time of 400 s, adsorption and desorption pressures of 10 and 1 bar, respectively, and a purge flow rate of 100 mol/s. This technoeconomic assessment shows that the integrated combined system can be an attractive technology compared to multi-step systems for the removal of flue gas impurities.

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“…Air Products has studied a system for CO 2 -rich stream desulfurization during the compression stage using NO x as catalyst for the production of H 2 SO 4 and the produced HNO 3 is used to remove mercury [20]. An alternative novel method for SO x removal is the use of activated carbon [21,22] If no acid gas removal unit is employed in an IGCC integrated with chemical looping technology, the syngas stream that is fed to the CLC reactors, contains sulfur, so the oxygen carrier needs to be sulfur tolerant and therefore H 2 S is converted to SO 2 or it leaves the reactor as H 2 S. Afterwards, the CO 2 stream is desulfurized by FGD (flue gas desulfurization) and compressed.…”

Section: Introductionmentioning

confidence: 99%