Assessment of flexible energy vectors poly-generation based on coal and biomass/solid wastes co-gasification with carbon capture

This paper evaluates biomass and solid wastes co-gasification with coal for energy vectors poly-generation with carbon capture. The evaluated co-gasification cases were evaluated in term of key plant performance indicators for generation of totally or partially decarbonized energy vectors (power, hydrogen, substitute natural gas, liquid fuels by Fischer–Tropsch synthesis). The work streamlines one significant advantage of gasification process, namely the capability to process lower grade fuels on condition of high energy efficiency. Introduction in the evaluated IGCC-based schemes of carbon capture step (based on pre-combustion capture) significantly reduces CO₂ emissions, the carbon capture rate being higher than 90% for decarbonized energy vectors (power and hydrogen) and in the range of 47–60% for partially decarbonized energy vectors (SNG, liquid fuels). Various plant concepts were assessed (e.g. 420–425 MW net power with 0–200 MW_th flexible hydrogen output, 800 MW_th SNG, 700 MW_th liquid fuel, all of them with CCS). The paper evaluates fuel blending for optimizing gasification performance. A detailed techno-economic evaluation for hydrogen and power co-generation with CCS was also presented.     

Investigation of hydrogen and power co-generation based on direct coal chemical looping systems

This paper evaluates hydrogen and power co-generation based on direct coal chemical looping systems with total decarbonization of the fossil fuel. As an illustrative example, an iron-based chemical looping system was assessed in various plant configurations. The designs generate 300–450 MW net electricity with flexible hydrogen output in the range of 0–200 MW_th (LHV). The capacity of evaluated plant concepts to have a flexible hydrogen output is an important aspect for integration in modern energy conversion systems. The carbon capture rate of evaluated concepts is almost total (>99%). The paper presents in details evaluated plant configurations, operational aspects as well as mass and energy integration issues. For comparison reason, a syngas-based chemical looping concept and Selexol^®-based pre-combustion capture configuration were also presented. Direct coal chemical looping configuration has significant advantages compared with syngas-based looping systems as well as solvent-based carbon capture configurations, the more important being higher energy efficiency, lower (or even zero) oxygen consumption and lower plant complexity. The results showed a clear increase of overall energy efficiency in comparison to the benchmark cases.     

Hydrogen and power co-generation based on coal and biomass/solid wastes co-gasification with carbon capture and storage

This paper investigates the potential use of renewable energy sources (various sorts of biomass) and solid wastes (municipal wastes, sewage sludge, meat and bone meal etc.) in a co-gasification process with coal to co-generate hydrogen and electricity with carbon capture and storage (CCS). The paper underlines one of the main advantages of gasification technology, namely the possibility to process lower grade fuels (lower grade coals, renewable energy sources, solid wastes etc.), which are more widely available than the high grade coals normally used in normal power plants, this fact contributing to the improvement of energy security supply. Based on a proposed plant concept that generates 400–500 MW net electricity with a flexible output of 0–200 MW_th hydrogen and a carbon capture rate of at least 90%, the paper develops fuel selection criteria for coal blending with various alternative fuels for optimizing plant performance e.g. oxygen consumption, cold gas efficiency, hydrogen production and overall energy efficiency. The key plant performance indicators were calculated for a number of case studies through process flow simulations (ChemCAD).     

Use of lower grade coals in IGCC plants with carbon capture for the co-production of hydrogen and electricity

This paper investigates the potential use of lower grade coals in an IGCC-CCS plant that generates electricity and produces hydrogen simultaneously with carbon dioxide capture and storage. The paper underlines one of the main advantages of gasification technology, namely the possibility to process lower grade coals, which are more widely available than the high-grade coals normally used in European power plants. Based on a proposed plant concept that generates about 400 MW net electricity with a flexible output of 0–50 MW_th hydrogen and a carbon capture rate of at least 90%, the paper develops fuel selection criteria for coal fluxing and blending of various types of coal for optimizing plant performance e.g. oxygen consumption, hydrogen production potential, specific syngas energy production per tonne of oxygen consumed, etc. These performance indicators were calculated for a number of case studies through process flow simulations. The main conclusion is that blending of coal types of higher and lower grade is more beneficial in terms of operation and cost performance than fluxing high-grade coals.     

Evaluation of syngas-based chemical looping applications for hydrogen and power co-generation with CCS

This paper evaluates hydrogen and power co-generation based on coal-gasification fitted with an iron-based chemical looping system for carbon capture and storage (CCS). The paper assess in details the whole hydrogen and power co-production chain based on coal gasification. Investigated plant concepts of syngas-based chemical looping generate about 350–450 MW net electricity with a flexible output of 0–200 MW_th hydrogen (based on lower heating value) with an almost total decarbonisation rate of the coal used.     

Thermodynamic analysis of high‐ash coal‐fired power plant with carbon dioxide capture

A thermodynamic analysis of a 500‐MWe subcritical power plant using high‐ash Indian coal (base plant) is carried out to determine the effects of carbon dioxide (CO₂) capture on plant energy and exergy efficiencies. An imported (South African) low‐ash coal is also considered to compare the performance of the integrated plant (base plant with CO₂ capture plant). Chemical absorption technique using monoethanolamine as an absorbent is adopted in the CO₂ capture plant. The flow sheet computer program “Aspen Plus” is used for the parametric study of the CO₂ capture plant to determine the minimum energy requirement for absorbent regeneration at optimum absorber–stripper configuration. Energy and exergy analysis for the integrated plant is carried out using the power plant simulation software “Cycle‐Tempo”. The study also involves determining the effects of various steam extraction techniques from the turbine cycle (intermediate‐pressure–low‐pressure crossover pipe) for monoethanolamine regeneration. It is found that the minimum reboiler heat duty is 373 MW_th (equivalent to 3.77 MJ of heat energy per kg of CO₂ captured), resulting in a drop of plant energy efficiency by approximately 8.3% to 11.2% points. The study reveals that the maximum energy and exergy losses occur in the reboiler and the combustor, respectively, accounting for 29% and 33% of the fuel energy and exergy. Among the various options for preprocessing steam that is extracted from turbine cycle for reboiler use, “addition of new auxiliary turbine” is found to be the best option. Copyright © 2011 John Wiley & Sons, Ltd.     

ZECOMIX: Performance of alternative lay-outs

ZECOMIX is a plant for hydrogen production and power generation using coal as a primary energy source and with nearly zero emissions. The global lay-out can be divided in 5 sectors: coal gasification, O₂ production, CO₂ capture, CO₂ sequestration, power generation. Coal is hydro gasified using a stream of hydrogen internally recycled. The syngas, mainly methane, is then reformed with steam and CaO in such a way to obtain a gaseous stream of hydrogen and steam separated from CaCO₃ which is solid. CaO is then regenerated inside a calciner which produce also a gaseous stream of CO₂ which has to be stored. The stream of hydrogen is burned with stoichiometric O₂ and the resulting steam is expanded in a steam power plant. After having focused our efforts on the coal gasification and CO₂ capture, we selected a layout for these sections and analysed the possibility to cogenerate hydrogen and power. The results confirmed that cogeneration is the most efficient solution and ZECOMIX seems to be an interesting option.     

Process simulation and techno-economic assessment of SER steam gasification for hydrogen production

In the SER (sorption enhanced reforming) gasification process a nitrogen-free, high calorific product gas can be produced. In addition, due to low gasification temperatures of 600–750 °C and the use of limestone as bed material, in-situ CO₂ capture is possible, leading to a hydrogen-rich and carbon-lean product gas. In this paper, results from a bubbling fluidised bed gasification model are compared to results of process demonstration tests in a 200 kW_th pilot plant.Based upon that, a concept for the hydrogen production via biomass SER gasification is studied in terms of efficiency and feasibility. Capital and operational expenditures as well as hydrogen production costs are calculated in a techno-economic assessment study. Furthermore, market framework conditions are discussed under which an economic hydrogen production via SER gasification is possible.     

Role of hydrogen storage in renewable energy management for Ontario

Effective energy storage and management is needed to manage intermittent renewable energy systems. Several jurisdictions around the world are planning to reduce or close their coal power plants to allow for renewable energy expansion, such as Ontario, Canada. Hydrogen storage, which is a promising energy storage option, is capable of meeting energy requirements that will arise from the shutdown of coal plants. In this paper, both economic and environmental feasibility of a hydrogen system linked with wind and hydroelectric plants in Ontario will be investigated. The Princefarm wind power plant and Beck1 hydro plant with production capacities of 189 MW and 490 MW, respectively, are analyzed in a case study for comparison purposes. The environmental analysis demonstrates the advantageous role of hydrogen storage and energy conversion. The overall system life-cycle yields 31.02 g CO₂ eq per 1 kW h power output of the system when hydrogen energy storage is adopted. The payback periods of the systems linked with the Princefarm and Beck1 are also analyzed and found to be about 17 years.     

Techno-economic and environmental performances of glycerol reforming for hydrogen and power production with low carbon dioxide emissions

This paper is evaluating from the conceptual design, thermal integration, techno-economic and environmental performances points of view the hydrogen and power generation using glycerol (as a biodiesel by-product) reforming processes at industrial scale with and without carbon capture. The evaluated hydrogen plant concepts produced 100,000 Nm³/h hydrogen (equivalent to 300 MW_th) with negligible net power output for export. The power plant concepts generated about 500 MW net power output. Hydrogen and power co-generation was also assessed. The CO₂ capture concepts used alkanolamine-based gas–liquid absorption. The CO₂ capture rate of the carbon capture unit is at least 90%, the carbon capture rate of the overall reforming process being at least 70%. Similar designs without carbon capture have been developed to quantify the energy and cost penalties for carbon capture. The various glycerol reforming cases were modelled and simulated to produce the mass & energy balances for quantification of key plant performance indicators (e.g. fuel consumption, energy efficiency, ancillary energy consumption, specific CO₂ emissions, capital and operational costs, production costs, cash flow analysis etc.). The evaluations show that glycerol reforming is promising concept for high energy efficiency processes with low CO₂ emissions.     

Supercritical water oxidation of coal in power plants with low CO2 emissions

In this paper, the application of Super Critical Water Oxidation (SCWO) to direct combustion at low temperature of coal fine particles with pure oxygen for power generation is presented, including also a novel method for capturing and storing carbon dioxide as liquid. A detailed simulation model of a 100 MW_th coal-fired SWCO plant with low CO₂ emissions characterised by a steam cooled membraned SC reactor has been developed using Aspen Plus software. According to the well-known Semenov's thermal-ignition theory, the coal particle ignition temperature in SCW conditions has been also evaluated and the results have been integrated within the Aspen Plus model. This has been tested under different operating conditions. The simulation results are presented and the effects of the main plant operating conditions, such as ignition temperature, coal particle size and combustion pressure on the plant performances are discussed. The gross and net thermodynamic efficiencies of the power plant have been estimated to be around 44% and 28%, respectively. The pure oxygen production process results the main energy penalty.     

Hydrogen production facility location selection for Black Sea using entropy based TOPSIS under IVPF environment

Parallel with the globally increment in energy demand, governments and responsible authorities’ environmental awareness increases and they have been taking several preventions not to harm environment while energy demand is satisfied. For this purpose decision makers turn their faces to satisfy energy demand via renewable energy sources such as wind, wave, solar, hydro, biomass, hydrogen etc. Before this awareness human was satisfying energy demand via nonrenewable energy sources such as natural gas, coal etc. Even though not being one of these energy sources, hydrogen energy is a primary energy carrying form which is known one of the energy carrier [1]. This study aims to select the most appropriate site in the northern of Turkey for establishing a hydrogen energy hydrogen-sulphide (H₂S) decomposition plant. Based on the researches, Black Sea is determined as one of the richest water to get H₂S from. Since selecting the facility location for hydrogen energy production plant requires strategical decisions, Multi Criteria Decision Making (MCDM), as a powerful and efficient tool, is preferred in this study. Accordingly, Entropy and Technique for Order of Preference by Similarity to Ideal Solution (TOPSIS) methodologies are integrated and applied under Interval Valued Pythagorean Fuzzy (IVPF) environment to deal with uncertain information better. The developed method is shown to be useful and effective in terms of applicability and ease of usage. As a result, the best suitable location is determined and sensitivity analysis is conducted to analyze the dynamics of the developed methodology.     

The potential of metal hydrides paired with compressed hydrogen as thermal energy storage for concentrating solar power plants

Concentrating solar power (CSP) plants require thermal energy storage (TES) systems to produce electricity during the night and periods of cloud cover. The high energy density of high-temperature metal hydrides (HTMHs) compared to state-of-the-art two-tank molten salt systems has recently promoted their investigation as TES systems. A common challenge associated with high-temperature metal hydride thermal energy storage systems (HTMH TES systems) is storing the hydrogen gas until it is required by the HTMH to generate heat. Low-temperature metal hydrides can be used to store the hydrogen but can comprise a significant proportion of the overall system cost and they also require thermal management, which increases the engineering complexity. In this work, the potential of using a hydrogen compressor and large-scale underground hydrogen gas storage using either salt caverns or lined rock caverns has been assessed for a number of magnesium- and sodium-based hydrides: MgH₂, Mg₂FeH₆, NaMgH₃, NaMgH₂F and NaH. Previous work has assumed that the sensible heat of the hydrogen released from the HTMH would be stored in a small, inexpensive regenerative material system. However, we show that storing the sensible heat of the hydrogen released would add between US$3.6 and US$7.5/kWh_th to the total system cost for HTMHs operating at 565 °C. If the sensible heat of released hydrogen is instead exploited to perform work then there is a flow-on cost reduction for each component of the system. The HTMHs combined with underground hydrogen storage all have specific installed costs that range between US$13.7 and US$26.7/kWh_th which is less than that for current state-of-the-art molten salt heat storage. Systems based on the HTMHs Mg₂FeH₆ or NaH have the most near term and long term potential to meet SunShot cost targets for CSP thermal energy storage. Increasing the operating temperature and hydrogen equilibrium pressure of the HTMH is the most effective means to reduce costs further.     

The integration of hybrid hydrogen networks for refinery and synthetic plant of chemicals

Hydrogen is the core source to both refinery and synthetic plant of chemicals. Refinery consumes high purity hydrogen while synthetic plant of chemicals needs syngas consists of hydrogen and carbon oxides. As main hydrogen production technologies, industrial coal gasification and steam methane reforming based pathways generate H₂, CO and CO₂, which is actually the mixture of hydrogen and carbon oxides. Hence, the gases demand of refinery and synthetic plant of chemicals and their supply from hydrogen production can form hybrid hydrogen networks. On the basis of complementary reuse, this paper firstly proposes integration of hybrid hydrogen network for refinery and synthetic plant of chemicals. Superstructures of individual and hybrid hydrogen networks are employed as problem illustration and corresponding linear programming (LP) mathematical models are formulated. Practical refinery and synthetic plant of chemicals cases are employed to demonstrate its application. Compared with individual networks, the natural gas conservation case can recover 8660.4 Nm³·h^-1 hydrogen in purge gas, reduce 1386.6 Nm³·h^-1 CO₂ emission, equaling to reduction of 278.11 kmol·h^-1 natural gas feedstock and 14.8% of total gas production load; the coal conservation case can even waive the total coal consumption and extra 104.1 kmol·h^-1 natural gas, recover 8660.4 Nm³·h^-1 hydrogen in purge gas, reduce 5255.8 Nm³·h^-1 of CO₂ emission and decrease 21.2% of the total gas production load. Furthermore, economic evaluation is also placed to account for the economic advantage of hybrid network.     

Large-scale production and transport of hydrogen from Norway to Europe and Japan: Value chain analysis and comparison of liquid hydrogen and ammonia as energy carriers

Low-carbon hydrogen is considered as one of the key measures to decarbonise continental Europe and Japan. Northern Norway has abundant renewable energy and natural gas resources which can be converted to low-carbon hydrogen. However, Norway is located relatively far away from these markets and finding efficient ways to transport this hydrogen to the end-user is critical. In this study, liquefied hydrogen (LH₂) and ammonia (NH₃), as H₂-based energy carriers, are analysed and compared with respect to energy efficiency, CO₂ footprint and cost. It is shown that the LH₂ chain is more energy efficient and has a smaller CO₂ footprint (20 and 23 kg-CO₂/MWh_th for Europe and Japan, respectively) than the NH₃ chain (76 and 122 kg-CO₂/MWh_th). Furthermore, the study finds the levelized cost of hydrogen delivered to Rotterdam to be lower for LH₂ (5.0 EUR/kg-H₂) compared to NH₃ (5.9 EUR/kg-H₂), while the hydrogen costs of the two chains for transport to Japan are in a similar range (about 7 EUR/kg-H₂). It is also shown that under optimistic assumptions, the costs associated with the LH₂ chain (3.2 EUR/kg-H₂) are close to meeting the 2030 hydrogen cost target of Japan (2.5 EUR/kg-H₂).     

Modelling of grate combustion in a medium scale biomass furnace for control purposes

A new mathematical model for the grate combustion of biomass has been derived from physical considerations. Various models for grate combustion can already be found in the literature. Usually their intention is to simulate the real situation in a furnace as precisely as possible. Hence they are very detailed, typically consisting of many partial differential equations. However, because of their complexity they are useless for control purposes. The new model is very simple, consisting of only two ordinary differential equations, which makes it particularly suitable as a basis for model based control strategies. To verify the model, experiments were performed at a pilot scale furnace with horizontally moving grate. The pilot plant is a downscaled version (180 kW_th) of a typical medium scale furnace in terms of geometry and instrumentation. Comparison of the measured and calculated values shows good agreement.     

Economic evaluation of the solar carbothermic reduction of ZnO by using a single sensitivity analysis and a Monte-Carlo risk analysis

The technical feasibility of the solar carbothermal reduction of ZnO has been successfully demonstrated in a pilot plant. The economics of this process is addressed by means of a single sensitivity analysis and a Monte-Carlo risk analysis. A medium-term and a long-term scenario have been investigated, each for a 5 and a 30 MW_th plant. For a discount rate of 15% the zinc production costs vary between 482 and 245 $/t for the medium-term scenario and between 312 and 146 $/t for the long-term scenario, respectively. These costs do not account for the zinc oxide input material. In addition, a risk analysis was conducted for the 30 MW_th long-term scenario. For each input parameter, a probability distribution was estimated and the probability distribution of the zinc production cost was calculated by means of a Monte-Carlo method. The expected mean zinc production costs vary from 95 $/t for a discount rate of 0%–286 $/t for a discount rate of 40%.     

Economic comparison of solar hydrogen generation by means of thermochemical cycles and electrolysis

Hydrogen is acclaimed to be an energy carrier of the future. Currently, it is mainly produced by fossil fuels, which release climate-changing emissions. Thermochemical cycles, represented here by the hybrid-sulfur cycle and a metal oxide based cycle, along with electrolysis of water are the most promising processes for ‘clean’ hydrogen mass production for the future. For this comparison study, both thermochemical cycles are operated by concentrated solar thermal power for multistage water splitting. The electricity required for the electrolysis is produced by a parabolic trough power plant. For each process investment, operating and hydrogen production costs were calculated on a 50 MW_th scale. The goal is to point out the potential of sustainable hydrogen production using solar energy and thermochemical cycles compared to commercial electrolysis. A sensitivity analysis was carried out for three different cost scenarios. As a result, hydrogen production costs ranging from 3.9–5.6 €/kg for the hybrid-sulfur cycle, 3.5–12.8 €/kg for the metal oxide based cycle and 2.1–6.8 €/kg for electrolysis were obtained.     

Heat extraction from supercritical water-cooled nuclear reactors for hydrogen production plants

Many current and future hydrogen production methods, such as steam methane reforming and thermochemical water splitting cycles, require large amounts of heat as the major energy input. Using nuclear heat is a promising option for reducing emissions of greenhouse gases and other pollutants, thereby helping achieve clean and sustainable future energy systems. Various heat transfer fluids are compared and evaluation criteria are proposed for the selection of a heat transfer fluid. It is determined that helium is a promising option due to it being inert and chemically stable and having good heat transfer properties. The intermediate heat exchanger for the heat extraction is analyzed and designed using the log mean temperature difference (LMTD) method with helium serving as the heat transfer fluid to extract heat from the supercritical water. It is found that if the heat extraction load is in the range of 100–330 MW_th, which approximately corresponds to a hydrogen production range of 40–125 tonnes per day, then a multi-tube and single-shell counter flow heat exchanger with a shell diameter of 0.7–1.3 m and length of 6.7 m encapsulating 420–1600 tubes of 0.025 m diameter would be appropriate according to the practical working conditions on the shell and tube sides. The analysis also shows that the diameter of the heat exchanger does not depend strongly on the heat transfer load if the load is smaller than 330 MW_th (125 tonnes H₂/day). This provides flexibility in case adjustments to the heat extraction load become necessary. However, if the heat load is larger than 330 MW_th, for example, 500 MW_th for 200 tonnes hydrogen per day, then a multi-tube and single-shell counter flow heat exchanger is not appropriate because the length-to-diameter ratio is outside of the recommended range.     

Production of hydrogen and methanol from natural gas with reduced CO2 emission

The thermal decomposition of natural gas forms the basis for the production of hydrogen with reduced CO₂ emission. The hydrogen can be used to reduce CO₂ from coal-fired power plants to produce methanol which can be used as an efficient automotive fuel. The kinetics of methane decomposition is studied in a one inch diameter tubular reactor at temperatures between 700 and 900 °C and at pressures between 28 and 56 atm. The Arrhenius activation energy is found to be 31.3kcal/mol of CH₄. The rate increases with higher pressures and appears to be catalyzed by the presence of carbon particles formed. The conversion increases with temperature and is equilibrium limited. A thermodynamic study indicates that hydrogen produced by methane decomposition while sequestering the carbon produced requires the least amount of process energy with zero CO₂ emission. Application to methanol synthesis by reacting the hydrogen with CO₂ recovered from coal burning power plant stack gases can significantly reduce CO₂ from both the utility and transportation sectors. Published by Elsevier Science Ltd on behalf of the International Association for Hydrogen Energy.