Multifracture response to supercritical CO2‐EGS and water‐EGS based on thermo‐hydro‐mechanical coupling method

Hydraulic‐fracturing treatments have become an essential technology for the development of deep hot dry rocks (HDRs). The deep rock formation often contains natural fractures (NFs) at micro and macroscales. In the presence of the NF, the hydraulic‐fracturing process may form a complex fracture network caused by the interaction between hydraulic fractures and NF. In this study, analysis of carbon dioxide (CO₂)‐based enhanced geothermal system (EGS) and water‐based EGS in complex fracture network was performed based on the thermo‐hydro‐mechanical (THM) coupling method, with various rock constitutive models. The complexity of the fracture geometry influences the fluid flow path and heat transfer efficiency of the thermal reservoir. Compared with CO₂‐based EGS, water‐based EGS had an earlier thermal breakthrough with a rapid decline in production temperature. CO₂ can easily gain heat rising its temperature thus reducing the effect of a premature thermal breakthrough. Both CO₂‐based EGS and water‐based EGS are affected by in‐situ stress; the increase in stress ratio improved the fracture permeability but resulted in an early cold thermal breakthrough. When the same injection rate is applied to water‐based EGS and CO₂‐based EGS, water‐based EGS displayed higher injection pressure buildup. Water‐based EGS had higher reservoir deformation area than CO₂‐based EGS, and thermoelastic constitutive model for water‐based EGS showed larger deformed area ratio than thermo‐poroelastic rock model. Furthermore, higher values of rock modulus accelerated the reservoir deformation for water‐based EGS. This study established a novel discussion investigating the performance of CO₂‐based EGS and water‐based EGS in a complex fractured reservoir. The findings from this study will help in deepening the understanding of the mechanisms involved when using CO₂ or water as a working fluid in EGS.     

Extending existing combined heat and power plants for synthetic natural gas production

In this work, integration of a synthetic natural gas (SNG) production process with an existing biomass CHP steam power cycle is investigated. The paper assesses two different biomass feedstock drying technologies—steam drying and low‐temperature air drying—for the SNG process. Using pinch technology, different levels of thermal integration between the steam power cycle and the SNG process are evaluated. The base case cold gas efficiency for the SNG process is 69.4% based on the lower heating value of wet fuel. The isolated SNG‐related electricity production is increased by a factor of 2.5 for the steam dryer alternative, and tenfold for the low‐temperature air dryer when increasing the thermal integration. The cold gas efficiency is not affected by the changes. Based on an analysis of changes to turbine steam flow, the integration of SNG production with an existing steam power cycle is deemed technically feasible. Copyright © 2011 John Wiley & Sons, Ltd.     

Technical assessment of synthetic natural gas （SNG） production from agricul- ture residuals

This paper presents thermodynamic evaluations of the agriculture residual-to-SNG process by thermochemical conversion, which mainly consists of the interconnected fluidized beds, hot gas cleaning, fluidized bed methanation reactor and Selexol absorption unit. The process was modeled using Aspen Plus software. The process performances, i.e., CH 4 content in SNG, higher heating value and yield of SNG, exergy efficiencies with and without heat recovery, unit power consumption, were evaluated firstly. The results indicate that when the other parameters remain unchanged, the steam-to-biomass ratio at carbon boundary point is the optimal value for the process. Improving the preheating temperatures of air and gasifying agent is beneficial for the SNG yield and exergy efficiencies. Due to the effects of CO 2 removal efficiency, there are two optimization objectives for the SNG production process: (I) to maximize CH 4 content in SNG, or (II) to maximize SNG yield. Further, the comparison among different feedstocks indicates that the decreasing order of SNG yield is: corn stalk > wheat straw > rice straw. The evaluation on the potential of agriculture-based SNG shows that the potential annual production of agriculture residual-based SNG could be between 555×10 8～611×10 8 m 3 with utilization of 100% of the available unexplored resources. The agriculture residual-based SNG could play a significant role on solving the big shortfall of China’s natural gas supply in future.     

Small‐scale production of synthetic natural gas by allothermal biomass gasification

The gasification of biomass can be coupled to a downstream methanation process that produces synthetic natural gas (SNG). This enables the distribution of bioenergy in the existing natural gas grid. A process model is developed for the small‐scale production of SNG with the use of the software package Aspen Plus (Aspen Technology, Inc., Burlington, MA, USA). The gasification is based on an indirect gasifier with a thermal input of 500 kW. The gasification system consists of a fluidized bed reformer and a fluidized bed combustor that are interconnected via heat pipes. The subsequent methanation is modeled by a fluidized bed reactor. Different stages of process integration between the endothermic gasification and exothermic combustion and methanation are considered. With increasing process integration, the conversion efficiency from biomass to SNG increases. A conversion efficiency from biomass to SNG of 73.9% on a lower heating value basis is feasible with the best integrated system. The SNG produced in the simulation meets the quality requirements for injection into the natural gas grid. Copyright © 2012 John Wiley & Sons, Ltd.     

Implications of system expansion for the assessment of well‐to‐wheel CO2 emissions from biomass‐based transportation

In this paper we show the effects of expanding the system when evaluating well‐to‐wheel (WTW) CO₂ emissions for biomass‐based transportation, to include the systems surrounding the biomass conversion system. Four different cases are considered: DME via black liquor gasification (BLG), methanol via gasification of solid biomass, lignocellulosic ethanol and electricity from a biomass integrated gasification combined cycle (BIGCC) used in a battery‐powered electric vehicle (BPEV). All four cases are considered with as well as without carbon capture and storage (CCS). System expansion is used consistently for all flows. The results are compared with results from a conventional WTW study that only uses system expansion for certain co‐product flows. It is shown that when expanding the system, biomass‐based transportation does not necessarily contribute to decreased CO₂ emissions and the results from this study in general indicate considerably lower CO₂ mitigation potential than do the results from the conventional study used for comparison. It is shown that of particular importance are assumptions regarding future biomass use, as by expanding the system, future competition for biomass feedstock can be taken into account by assuming an alternative biomass usage. Assumptions regarding other surrounding systems, such as the transportation and the electricity systems are also shown to be of significance. Of the four studied cases without CCS, BIGCC with the electricity used in a BPEV is the only case that consistently shows a potential for CO₂ reduction when alternative use of biomass is considered. Inclusion of CCS is not a guarantee for achieving CO₂ reduction, and in general the system effects are equivalent or larger than the effects of CCS. DME from BLG generally shows the highest CO₂ emission reduction potential for the biofuel cases. However, neither of these options for biomass‐based transportation can alone meet the needs of the transport sector. Therefore, a broader palette of solutions, including different production routes, different fuels and possibly also CCS, will be needed. Copyright © 2009 John Wiley & Sons, Ltd.     

Lignin‐derived heteroatom‐doped porous carbons for supercapacitor and CO2 capture applications

The present study reports the economic and sustainable syntheses of functional porous carbons for supercapacitor and CO₂ capture applications. Lignin, a byproduct of pulp and paper industry, was successfully converted into a series of heteroatom‐doped porous carbons (LHPCs) through a hydrothermal carbonization followed by a chemical activating treatment. The prepared carbons include in the range of 2.5 to 5.6 wt% nitrogen and 54 wt% oxygen in its structure. All the prepared carbons exhibit micro‐ and mesoporous structures with a high surface area in the range of 1788 to 2957 m² g^?1. As‐prepared LHPCs as an active electrode material and CO₂ adsorbents were investigated for supercapacitor and CO₂ capture applications. Lignin‐derived heteroatom‐doped porous carbon 850 shows an outstanding gravimetric specific capacitance of 372 F g^?1 and excellent cyclic stability over 30,000 cycles in 1 M KOH. Lignin‐derived heteroatom‐doped porous carbon 700 displays a remarkable CO₂ capture capacity of up to 4.8 mmol g^?1 (1 bar and 298 K). This study illustrates the effective transformation of a sustainable waste product into a highly functional carbon material for energy storage and CO₂ separation applications.     

Microbial electrolysis cells for production of methane from CO2: long‐term performance and perspectives

A methane‐producing microbial electrolysis cell (MEC) is a technology to convert CO₂ into methane, using electricity as an energy source and microorganisms as the catalyst. A methane‐producing MEC provides the possibility to increase the fuel yield per hectare of land area, when the CO₂ produced in biofuel production processes is converted to additional fuel methane. Besides increasing fuel yield per hectare of land area, this also results in more efficient use of land area, water, and nutrients. In this research, the performance of a methane‐producing MEC was studied for 188 days in a flat‐plate MEC design. Methane production rate and energy efficiency of the methane‐producing MEC were investigated with time to elucidate the main bottlenecks limiting system performance. When using water as the electron donor at the anode during continuous operation, methane production rate was 0.006 m³/m³ per day at a cathode potential of ?0.55 V vs. normal hydrogen electrode with a coulombic efficiency of 23.1%. External electrical energy input was 73.5 kWh/m³ methane, resulting in a voltage efficiency of 13.4%. Consequently, overall energy efficiency was 3.1%. The maximum achieved energy efficiency was obtained in a yield test and was 51.3%. Analysis of internal resistance showed that in the short term, cathode and anode losses were dominant, but with time, also pH gradient and transport losses became more important. The results obtained in this study are used to discuss the possible contribution of methane‐producing MECs to increase the fuel yield per hectare of land area. Copyright © 2011 John Wiley & Sons, Ltd.     

A cryogen‐based peak‐shaving technology: systematic approach and techno‐economic analysis

A peak‐shaving technology is recently proposed, which integrates peak‐electricity generation, cryogenic energy storage and CO₂ capture. In such a technology, off‐peak electricity is used to produce liquid nitrogen and oxygen in an air separation and liquefaction unit. At peak hours, natural gas (or alternative gases, e.g. from gasification of coal) is burned by oxygen from the air separation unit (oxy‐fuel combustion) to generate electricity. CO₂ produced is captured in the form of dry ice. Liquid nitrogen produced in the air separation plant not only serves as an energy storage medium but also supplies the low‐grade cold energy for CO₂ separation. In addition, waste heat from the tail gas can be used to superheat nitrogen in the expansion process to further increase the system efficiency. This article reports a systematic approach, with an aim to provide technical information for the system design. Three potential blending gases (helium, oxygen and CO₂) are considered not only for assessing thermodynamic performance but also for techno‐economic analysis. The peak‐shaving systems are also compared with natural gas combined cycle and an oxy–natural gas combined cycle in terms of capital cost and peak electricity production cost. Copyright © 2011 John Wiley & Sons, Ltd.     

Systems analysis of different value chains based on domestic forest biomass for the production of bio‐SNG

This study compares value chains based on domestic forest biomass for the production of bio–synthetic natural gas (SNG) with respect to economic performance, GHG emissions, and energy efficiency. Value chains in which raw material is upgraded to intermediate products before transportation to an SNG plant integrated with a district heating system for further upgrading are compared with a chain in which the raw material is transported directly to the SNG plant. The intermediates considered are either dried biomass from forest residues, or bark, upgraded at pulp mills, or pellets from sawdust upgraded at sawmills. The findings show that the difference in performance between the studied value chains is generally small. The highest cost and significantly lowest energy efficiency are associated with the value chain with pellets, which leads to the conclusion that more pretreatment than what is required by the SNG process, to lower transport costs, is not profitable. Drying forest residues at pulp mills before further transportation to and upgrading at an SNG plant leads to somewhat higher transportation costs because of the relatively high fixed costs associated with transportation. However, the benefit of drying the biomass using excess heat at pulp mills is that heat is “moved” from a location, where it can be hard to find profitable ways to use it, to the SNG plant, where the excess heat can be used for district heating. With these two factors working in opposition, the total cost is similar if forest residues are transported directly to the SNG plant or via a pulp mill. The lowest cost is achieved when falling bark from pulp mills is used because the first transportation step is avoided and no additional investment for biomass handling at the mill is required. However, there is a technical uncertainty regarding how much bark can be used in the SNG process.     

Syngas production via CO2 reforming of methane over plasma assisted synthesized Ni‐Co/Al2O3‐ZrO2 nanocatalysts with different Ni‐loadings

Ni‐Co/Al₂O₃‐ZrO₂ nanocatalysts with 5, 10 and 15 wt.% nominal Ni content have been prepared by impregnation followed by a non‐thermal plasma treatment, characterized and tested for dry reforming of methane. For nanocatalysts characterization the following techniques have been used: XRD, FESEM, TEM, EDX dot‐mapping, BET, FTIR and XPS. The dry reforming of methane was carried out at different temperatures (550‐850 °C) using a feed mixture of CH₄:CO₂ (1:1). Among the nanocatalysts studied, the catalyst with the medium Ni content (10 wt.%) was the most active in dry reforming of methane. This higher activity exhibited by Ni‐Co/Al₂O₃‐ZrO₂ catalyst with medium Ni content (10 wt.% ) can be attributed to small and well dispersed particles of Ni within the catalyst. Apart from the narrow surface particle size distribution in the case of Ni(10 wt.%)‐Co/Al₂O₃‐ZrO₂, the presence of small active components with average size of 7.5 nm is proposed to be the reason for the superior performance of the catalyst. Ni(10 wt.%)‐Co/Al₂O₃‐ZrO₂ nanocatalyst had maximum surface area and the lower surface area was observed in the case of Ni(5 wt.%)‐Co/Al₂O₃‐ZrO₂ and Ni(15 wt.%)‐Co/Al₂O₃‐ZrO₂ due to the formation of the larger agglomeration and higher mean particle size of nickel particles, respectively. Although, GHSV enhancment had inverse effect on product yield but yield reduction for Ni‐Co/Al₂O₃‐ZrO₂ catalyst with 10 wt.% Ni was less drastic at high GHSVs. According to XRD and XPS, existence of NiAl₂O₄ confirms strong interaction between Ni and support but higher loadings of Ni resulted in less NiAl₂O₄; loser interaction between support and active phase. Small particles of active components and well‐defined dispersion of them in Ni(10 wt.%)‐Co/Al₂O₃‐ZrO₂ nanocatalyst resulted in stability of the catalyst for either feed conversion or H₂/CO molar ratio. Copyright © 2013 John Wiley & Sons, Ltd.     

A comprehensive techno‐economic analysis method for power generation systems with CO2 capture

A new comprehensive techno‐economic analysis method for power generation systems with CO₂ capture is proposed in this paper. The correlative relationship between the efficiency penalty, investment increment, and CO₂ avoidance cost is established. Through theoretical derivation, typical system analysis, and variation trends investigation, the mutual influence between technical and economic factors and their impacts on the CO₂ avoidance cost are studied. At the same time, the important role that system integration plays in CO₂ avoidance is investigated based on the analysis of a novel partial gasification CO₂ recovery system. The results reveal that for the power generation systems with CO₂ capture, the efficiency penalty not only affects the costs on fuel, but the incremental investment cost for CO₂ capture (U.S.$ kW⁻¹) as well. Consequently, it will have a decisive impact on the CO₂ avoidance cost. Therefore, the added attention should be paid to improve the technical performance in order to reduce the efficiency penalty in energy system with CO₂ capture and storage. Additionally, the system integration may not only decrease the efficiency penalty, but also simplify the system structure and keep the investment increment at a low level, and thereby it reduces the CO₂ avoidance cost significantly. For example, for the novel partial gasification CO₂ recovery system, owing to system integration, its efficiency can reach 42.2%, with 70% of CO₂ capture, and its investment cost is only 87$ kW⁻¹ higher than that of the reference IGCC system, thereby the CO₂ avoidance cost is only 6.23$ t⁻¹ CO₂. The obtained results provide a comprehensive technical–economical analysis method for energy systems with CO₂ capture useful for reducing the avoidance costs. Copyright © 2009 John Wiley & Sons, Ltd.     

A critical assessment of thermo‐economic analyses of different air bottoming cycles for waste heat recovery

Steam turbine cycle's low operating temperature makes it suitable for waste heat recovery applications. Even though conventional combined cycles, ie, topping gas turbine and bottoming steam turbine cycles, are thermodynamically efficient, they are not the most economical alternatives for power generation with capacities less than 50 MWe. A recently proposed alternative is to utilize a bottoming gas turbine cycle in form of an air bottoming cycle. In this study, an overview of air bottoming cycle is presented. Based on the discussed studies, it is decided to further evaluate the merits of water injection in the bottoming cycle air stream by using either a humidifier or an air saturator. Thermo‐economic analysis and optimization are performed to evaluate simple and water injected air bottoming cycles against steam bottoming cycles. Results indicate that conventional combined cycles can achieve the highest thermal efficiency of about 48%. While water injected air bottoming cycle with air saturator is the most cost effective combined cycle configuration and most efficient air bottoming cycle with levelized cost of electricity and energy efficiency of 64.41 US$/MWh and 39%–40%, respectively, followed by the water injected air bottoming cycle with humidifier and simple air bottoming cycle with reported levelized cost of electricity of 65.75 US$/MWh, 66.36 US$/MWh, respectively. Steam bottoming cycle has the highest levelized cost of electricity of 68.88 US$/MWh.     

Thermo‐economic investigation: an insight tool to analyze NGCC with calcium‐looping process and with chemical‐looping combustion for CO2 capture

In this work, three kinds of natural gas‐based power generation processes for CO₂ capture and storage, that is, natural gas‐combined cycle with pre‐combustion decarburization (NGCC‐PRE), NGCC‐PRE with calcium‐looping process, and NGCC‐PRE with chemical‐looping combustion (NGCC‐CLC), are analyzed by Aspen Plus. The effects of two decisive variables (i.e., steam‐to‐natural gas (S/NG) ratio and oxygen‐to‐natural gas (O/NG) ratio) on the thermodynamic performances of individual process, such as energy and exergy efficiencies, are investigated systematically. Based on simulation outcomes, all the three processes are favored by operating at S/NG = 2.0 and O/NG = 0.65. Furthermore, comparisons of individual system efficiencies and exergy destruction contributor are herein involved. The results show that the highest system efficiencies and lowest exergy destruction are achieved in the NGCC‐CLC process. In addition, capital investment, dynamic payback period, net present value, and internal rate of return are used for deciding the economic feasibility and surely are involved in this work for comparison purpose. Copyright © 2016 John Wiley & Sons, Ltd.     

Energy minimization in monoethanolamine‐based CO2 capture using capacitive deionization

Post‐combustion CO₂ capture using monoethanolamine (MEA) is a mature technology; however, the high energy input requirements for solvent regeneration are still a challenge for MEA‐based CO₂ capture. In this paper, a novel approach is presented in which a conventional CO₂ absorption–desorption system is integrated with capacitive deionization (CDI) in such a way to minimize the heat duty requirement of the stripper. The CO₂‐rich solution drawn from the absorber column is first sent to CDI where ionic species are adsorbed at oppositely charged electrodes during the charging cycle, and an ion‐free solution is sent back to the absorber. The adsorbed ions released during the regeneration cycle are sent to the stripper column. The concentrated solution from the CDI process that was sent to the stripper required low heat duty to regenerate the solvent because of the high CO₂ loading of the solution. The feasibility of the suggested modelling technique is verified at various stripper inlet temperatures and lean CO₂ loadings. The results indicate that 10–45% of the total energy supplied to the stripper can be conserved at a lean CO₂ loading of 0.0000–0.0323 using the suggested process model. Moreover, the required size of the stripper column will be small due to the small volume of the concentrated ionic solutions from the CDI cell, eliminating the initial cost of the CO₂ capture system. Copyright © 2014 John Wiley & Sons, Ltd.     

Thermochemical CO2 splitting using a sol‐gel–synthesized Mg‐ferrite–based redox system

The synthesis, characterization, and application of the Mg_xFe_3?xO₄ (MF) redox materials towards conversion of CO₂ via thermochemical redox reactions are reported. Sol‐gel method was utilized for the synthesis of MF materials. The derived MF materials were characterized to determine the physicochemical properties using various analytical techniques. PXRD results authorized the phase pure composition, and the SEM analysis designated nanoparticulated morphology of all the synthesized MF materials. The MF materials were further tested to estimate their O₂ releasing and CO production ability in multiple thermochemical cycles using a high‐temperature thermogravimetric analyzer (TGA). Attained outcomes specify that the MgFe₂O₄ (MF10) was superior in terms of the thermal reduction and CO₂ splitting capacity as compared with the other MF materials. For instance, MF10 liberated 58.7 μmol of O₂/g·cycle and produced 79.6 μmol of CO/g·cycle with an average O₂ recovery of 67.7%/cycle in nine thermochemical cycles.     

Techno‐economic analysis of biomass/coal Co‐gasification IGCC systems with supercritical steam bottom cycle and carbon capture

In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and $0.06–$0.07/kW‐h. The SO_x emissions also decrease by about 190 tons/year (7.6 × 10^?6 tons/MW‐year). Finally, the CCS cost is around $65–$72 per ton of CO₂. For pre‐combustion CCS, sour shift appears to be superior both economically and thermally to sweet shift in the current study. Sour shift is always cheaper, (by a difference of about $600/kW and $0.02‐$0.03/kW‐h), easier to implement, and also 2–3 percentage points more efficient. The economic difference is fairly marginal, but the trend is inversely proportional to the efficiency, with cost of electricity decreasing by 0.5 cents/kW‐h from 0% to 10% biomass ratio (BMR) and rising 2.5 cents/kW‐h from 10% to 50% BMR. Pre‐combustion CCS plants are smaller than post‐combustion ones and usually require 25% less energy for CCS due to their compact size for processing fuel flow only under higher pressure (450 psi), versus processing the combusted gases at near‐atmospheric pressure. Finally, the CO₂ removal cost for sour shift is around $20/ton, whereas sweet shift's cost is around $30/ton, which is much cheaper than that of post‐combustion CCS: about $60–$70/ton. Copyright © 2014 John Wiley & Sons, Ltd.     

Novel hydrogen‐rich gas production by steam gasification of biomass in a research‐scale rotary tubular helical coil gasifier

The concept of biomass steam gasification offers platform for production (i) of hydrogen, (ii) hydrocarbons and (iii) value added chemicals. Majority of these developments are either in nascent or in pilot/demonstration stage. In this context, there exists potential for hydrogen production via biomass steam gasification. Gaseous products of biomass steam gasification consist of large percentage of CO, CH₄ and other hydrocarbons, which can be converted to hydrogen through water‐gas‐shift reaction, steam reforming and cracking respectively. Although there are many previous research works showing the potential of production of hydrogen from biomass in a two stage process, challenges remain in extended biomass and char gasification so as to reduce the amount of carbon in the residual char as well as improve conversion of heavy hydrocarbon condensates to hydrogen rich gas. In the current work, the characteristics of biomass steam gasification in an in‐house designed rotary tubular helical coil reactor at temperatures less than 850 °C, in the presence of superheated steam, were presented. The objectives were to obtain high carbon conversion in the primary biomass steam gasification step (upstream) and high product gas yield and hydrogen yield in the secondary fixed bed catalytic step (downstream). The influence of temperature, steam‐to‐biomass ratio and residence time on product gas yield in the rotary tubular helical coil gasifier was studied in detail using one of the abundantly available biomass sources in India‐rice husk. Further, enhancement of product gas yield and hydrogen yield in a fixed bed catalytic converter was studied and optimized. In the integrated pathway, a maximum gas yield of 1.92 Nm³/kg moisture‐free biomass was obtained at a carbon conversion efficiency of 92%. The maximum hydrogen purity achieved under steady state conditions was 53% by volume with a hydrogen yield of 91.5 g/kg of moisture‐free biomass. This study substantiates overall feasibility of production of high value hydrogen from locally available biomass by superheated steam gasification followed by catalytic conversion. Copyright © 2016 John Wiley & Sons, Ltd.     

Parametric techno‐economic studies of coal/biomass co‐gasification for IGCC plants with carbon capture using various coal ranks,fuel‐feeding schemes,and syngas cooling methods

Because of biomass's limited supply (as well as other issues involving its feeding and transportation), pure biomass plants tend to be small, which results in high production and capital costs (per unit power output) compared with much larger coal plants. Thus, it is more economically attractive to co‐gasify biomass with coal. Biomass can also make an existing plant carbon‐neutral or even carbon‐negative if enough carbon dioxide is captured and sequestered (CCS). As a part of a series of studies examining the thermal and economic impact of different design implementations for an integrated gasification combined cycle (IGCC) plant fed with blended coal and biomass, this paper focuses on investigating various parameters, including radiant cooling versus syngas quenching, dry‐fed versus slurry‐fed gasification (particularly in relation to sour‐shift and sweet‐shift carbon capture systems), oxygen‐blown versus air‐blown gasifiers, low‐rank coals versus high‐rank coals, and options for using syngas or alternative fuels in the duct burner for the heat recovery steam generator (HRSG) to achieve the desired steam turbine inlet temperature. Using the commercial software, Thermoflow^®, the case studies were performed on a simulated 250‐MW coal IGCC plant located near New Orleans, Louisiana, and the coal was co‐fed with biomass using ratios ranging from 10% to 30% by weight. Using 2011 dollars as a basis for economic analysis, the results show that syngas coolers are more efficient than quench systems (by 5.5 percentage points), but are also more expensive (by $500/kW and 0.6 cents/kW h). For the feeding system, dry‐fed is more efficient than slurry‐fed (by 2.2–2.5 points) and less expensive (by $200/kW and 0.5 cents/kW h). Sour‐shift CCS is both more efficient (by 3 percentage points) and cheaper (by $600/kW or 1.5 cents/kW h) than sweet‐shift CCS. Higher‐ranked coals are more efficient than lower‐ranked coals (2.8 points without biomass, or 1.5 points with biomass) and have lower capital cost (by $600/kW without using biomass, or $400/kW with biomass). Finally, plants with biomass and low‐rank coal feedstock are both more efficient and have lower costs than those with pure coal: just 10% biomass seems to increase the efficiency by 0.7 points and reduce costs by $400/kW and 0.3 cents/kW h. However, for high‐rank coals, this trend is different: the efficiency decreases by 0.7 points, and the cost of electricity increases by 0.1 cents/kW h, but capital costs still decrease by about $160/kW. Copyright © 2016 John Wiley & Sons, Ltd.     

ANFIS modeling of CO2 separation from natural gas using hollow fiber polymeric membrane

The present study is proposed to develop the Adaptive Neuro-Fuzzy Inference System optimized by genetic algorithm to estimate CO₂ value in permeate stream using a hollow fiber polymeric membrane for separation of binary gas containing CO₂ and CH₄ in natural gas. To that end, a number of 65 samples was gathered from the literature. Results indicated that the proposed ANFIS model has great potential with high correlation (R² = 0.9993) and less error (RMSE = 0.0064) for estimation of aforementioned parameter.     

微重力条件对小球藻固碳能力与油脂积累的影响

为了提高微藻的固碳效率和产脂速率,在模拟的微重力条件下,利用CO2培养蛋白核小球藻。实验结果表明:微重力条件和CO2对蛋白核小球藻的生长具有协同促进作用;与普通条件下通入空气培养蛋白核小球藻相比,在微重力条件下通入浓度为10%的CO2培养蛋白核小球藻120 h后,蛋白核小球藻的生物量浓度提高了178%;在普通条件下,蛋白核小球藻的固碳效率为2.64±0.41 mg/(L·h),在微重力条件下,蛋白核小球藻的固碳效率为17.28±0.42 mg/(L·h);在普通条件下通入CO2后,蛋白核小球藻细胞中的不饱和脂肪酸含量升高,而在微重力条件下通入CO2后,蛋白核小球藻细胞中的不饱和脂肪酸含量会下降。