Biomethanol production from gasification of non-woody plant in South Africa: Optimum scale and economic performance

Methanol production from biomass is a promising carbon neutral fuel, well suited for use in fuel cell vehicles (FCVs), as transportation fuel and as chemical building block. The concept used in this study incorporates an innovative Absorption Enhanced Reforming (AER) gasification process, which enables an efficient conversion of biomass into a hydrogen-rich gas (syngas) and then, uses the Mitsubishi methanol converter (superconverter) for methanol synthesis. Technical and economic prospects for production of methanol have been evaluated. The methanol plants described have a biomass input between 10 and 2000 MW_th. The economy of the methanol production plants is very dependent on the production capacity and large-scale facilities are required to benefit from economies of scale. However, large-scale plants are likely to have higher transportation costs per unit biomass transported as a result of longer transportation distances. Analyses show that lower unit investment costs accompanying increased production scale outweighs the cost for transporting larger quantities of biomass. The unit cost of methanol production mostly depends on the capital investments. The total unit cost of methanol is found to decrease from about 10.66 R/l for a 10 MW_th to about 6.44 R/l for a 60 MW_th and 3.95 R/l for a 400 MW_th methanol plant. The unit costs stabilise (a near flat profile was observed) for plant sizes between 400 and 2000 MW_th, but the unit cost do however continue to decrease to about 2.89 R/l for a 2000 MW_th plant. Long term cost reduction mainly resides in technological learning and large-scale production. Therefore, technology development towards large-scale technology that takes into account sustainable biomass production could be a better choice due to economic reasons.     

Theoretical calculation simulation studies of ABV nuclear reactor coupled with desalination system

In this paper, research has been conducted on the floating type nuclear power plant named as ABV reactor which is designed for district heating, power, and sea water desalination by OKBM facility at Russia. This reactor was tested under different thermal loads during the designing phase, and three modules have been investigated. Theoretical calculations and simulation studies have been performed on these three modules having specifications as ABV‐6M with 47MW_th, ABV‐6 with 38MW_th, and ABV‐3 with 18MW_th.The results obtained from these modules have been calculated mathematically and verified by simulation. We have compared the originally derived data of ABV desalination system with our theoretical and simulation analysis. The results from two desalination techniques including RO and RO + MED have been calculated and are presented in this paper with details. The results obtained from both analysis show that the efficiency of ABV nuclear reactor desalination system increases with the decrease in corresponding water cost ratio. Copyright © 2015 John Wiley & Sons, Ltd.     

Future prospects for production of methanol and hydrogen from biomass

Technical and economic prospects of the future production of methanol and hydrogen from biomass have been evaluated. A technology review, including promising future components, was made, resulting in a set of promising conversion concepts. Flowsheeting models were made to analyse the technical performance. Results were used for economic evaluations. Overall energy efficiencies are around 55% HHV for methanol and around 60% for hydrogen production. Accounting for the lower energy quality of fuel compared to electricity, once-through concepts perform better than the concepts aimed for fuel only production. Hot gas cleaning can contribute to a better performance. Systems of 400 MW_th input produce biofuels at US$ 8–12/GJ, this is above the current gasoline production price of US$ 4–6/GJ. This cost price is largely dictated by the capital investments. The outcomes for the various system types are rather comparable, although concepts focussing on optimised fuel production with little or no electricity co-production perform somewhat better. Hydrogen concepts using ceramic membranes perform well due to their higher overall efficiency combined with modest investment. Long-term (2020) cost reductions reside in cheaper biomass, technological learning, and application of large scales up to 2000 MW_th. This could bring the production costs of biofuels in the US$ 5–7/GJ range. Biomass-derived methanol and hydrogen are likely to become competitive fuels tomorrow.     

Highly efficient electricity generation from biomass by integration and hybridization with combined cycle gas turbine (CCGT) plants for natural gas

Integration/co-firing with existing fossil fuel plants could give near term highly efficient and low cost power production from biomass. This paper presents a techno-economical analysis on options for integrating biomass thermal conversion (optimized for local resources ∼50 MW_th) with existing CCGT (combined cycle gas turbine) power plants (800–1400 MW_th). Options include hybrid combined cycles (HCC), indirect gasification of biomass and simple cycle biomass steam plants which are simulated using the software Ebsilon Professional and Aspen Plus. Levelized cost of electricity (LCoE) is calculated with cost functions derived from power plant data. Results show that the integrated HCC configurations (fully-fired) show a significantly higher efficiency (40–41%, LHV (lower heating value)) than a stand-alone steam plant (35.5%); roughly half of the efficiency (2.4% points) is due to more efficient fuel drying. Because of higher investment costs, HCC options have cost advantages over stand-alone options at high biomass fuel prices (>25 EUR/MWh) or low discount rates (<5%). Gasification options show even higher efficiency (46–50%), and the lowest LCoE for the options studied for fuel costs exceeding 10 EUR/MWh. It can be concluded that clear efficiency improvements and possible cost reductions can be reached by integration of biomass with CCGT power plants compared to stand-alone plants.     

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.     

Solar chemical reactor technology for industrial production of lime

We developed the solar chemical reactor technology to effect the endothermic calcination reaction CaCO₃(s) → CaO(s) + CO₂(g) at 1200–1400 K. The indirect heating 10 kW_th multi-tube rotary kiln prototype processed 1–5 mm limestone particles, producing high purity lime that is not contaminated with combustion by-products. The quality of the solar produced quicklime meets highest industrial standards in terms of reactivity (low, medium, and high) and degree of calcination (exceeding 98%). The reactor’s efficiency, defined as the enthalpy of the calcination reaction at ambient temperature (3184 kJ kg⁻¹) divided by the solar energy input, reached 30–35% for quicklime production rates up to 4 kg h⁻¹. The solar lime reactor prototype operated reliably for more than 100 h at solar flux inputs of about 2000 kW m⁻², withstanding the thermal shocks that occur in solar high temperature applications. By substituting concentrated solar energy for fossil fuels as the source of process heat, one can reduce by 20% the CO₂ emissions in a state-of-the-art lime plant and by 40% in a conventional cement plant. The cost of solar lime produced in a 20 MW_th industrial solar calcination plant is estimated in the range 131–158 $/t, i.e. about 2–3 times the current selling price of conventional lime.     

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.     

CO2 sorbents for a sorption-enhanced water–gas-shift process in IGCC plants: A thermodynamic analysis and process simulation study

A sorption-enhanced water–gas-shift reaction process (SEWGS) combines the WGS reaction and CO₂ removal into a single process step in an integrated gasification combined cycle (IGCC) power plant. In the SEWGS, a solid sorbent is employed to capture the CO₂ generated by the WGS reaction. A key technical issue for the SEWGS is to identify and develop sorbents that can capture CO₂ under high pressure and high temperature syngas conditions and minimize or even eliminate the need for WGS catalysts. We present the results from a thermodynamic analysis and process simulation study that aimed to identify sorbents and optimal temperature windows to maximize the thermal efficiency of an IGCC + SEWGS plant. The results from the thermodynamic analysis identified two metal oxides, one silicate, three zirconates, and one titanate sorbents that are suitable for the SEWGS application. The results from the process simulation study revealed that the overall thermal efficiency of a 1187 MW_th (thermal input) IGCC + SEWGS plant gasifying an Illinois coal, and using the seven sorbents selected from the thermodynamic analysis, was between 0.5 and 2.4 percentage points greater than that of a reference IGCC + Selexol plant.     

Techno economic feasibility study on hydrogen production using concentrating solar thermal technology in India

The techno-economic analysis of hydrogen (H₂) production using concentrating solar thermal (CST) technologies is performed in this study. Two distinct hydrogen production methods, namely: a) thermochemical water splitting [model 1] and b) solid oxide electrolysers [model 2], are modeled by considering the total heat requirement and supplied from a central tower system located in Jaisalmer, India. The hourly simulated thermal energy obtained from the 10 MW_th central tower system is fed as an input to both these hydrogen production systems for estimating the hourly hydrogen production rate. The results revealed that these models yield hydrogen at a rate of 31.46 kg/h and 25.2 kg/h respectively for model 1 and model 2. Further, the Levelized cost of hydrogen (LCoH) for model 1 and model 2 is estimated as ranging from $ 8.23 and $ 14.25/kg of H₂ and $ 9.04 and $ 19.24/kg, respectively, for different scenarios. Overall, the present work displays a different outlook on real-time hydrogen production possibilities and necessary inclusions to be followed for future hydrogen plants in India. The details of the improvisation and possibilities to improve the LCoH are also discussed in this study.     

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%.     

Hydrogen production with CO2 capture by coupling steam reforming of methane and chemical-looping combustion: Use of an iron-based waste product as oxygen carrier burning a PSA tail gas

In this work it is analyzed the performance of an iron waste material as oxygen carrier for a chemical-looping combustion (CLC) system. CLC is a novel combustion technology with the benefit of inherent CO₂ separation that can be used as a source of energy for the methane steam reforming process (SR). The tail gas from the PSA unit is used as fuel in the CLC system.The oxygen carrier behaviour with respect to gas combustion was evaluated in a continuous 500 W_th CLC prototype using a simulated PSA off-gas stream as fuel. Methane or syngas as fuel were also studied for comparison purposes. The oxygen carrier showed enough high oxygen transport capacity and reactivity to fully convert syngas at 880 °C. However, lower conversion of the fuel was observed with methane containing fuels. An estimated solids inventory of 1600 kg MW_th⁻¹ would be necessary to fully convert the PSA off-gas to CO₂ and H₂O. An important positive effect of the oxygen carrier-to-fuel ratio up to 1.5 and the reactor temperature on the combustion efficiency was found.A characterization of the calcined and after-used particles was carried out showing that this iron-based material can be used as oxygen carrier in a CLC plant since particles maintain their properties (reactivity, no agglomeration, high durability, etc.) after more than 111 h of continuous operation.     

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.     

Performance analysis of cascaded thermoelectric converters for advanced radioisotope power systems

Advanced radioisotope power systems (ARPSs) for future planetary missions require higher conversion efficiency than the state-of-the-art (SOA) SiGe thermoelectric converter in order to decrease system mass and reduce mission cost. The performance of three cascaded thermoelectric converters (CTCs) for potential use in ARPSs is investigated at heat rejection temperatures of 375, 475 and 575 K and input thermal powers of 1, 2 and 3 W_th. These CTCs have top SiGe unicouples that are thermally, but not electrically, coupled to bottom unicouples having one of the following compositions: (a) TAGS-85 (p-leg) and 2N–PbTe (n-leg); (b) CeFe_3.5Co_0.5Sb₁₂ (p-leg) and CoSb₃ (n-leg); and (c) segmented p-leg of CeFe_3.5Co_0.5Sb₁₂ and Zn₄Sb₃ and n-leg of CoSb₃. The top and bottom unicouples in the CTCs are of the same length (10 mm), but the optimized cross-sectional areas of the n- and p-legs for maximum efficiency are different. The nominal hot junction temperature of the top SiGe unicouples at their peak efficiencies is 1273 K and that of the cold junction is 780 K when the bottom unicouple is of composition (a) and 980 K for compositions (b) and (c). The hot junction temperatures of the bottom unicouples are taken 20 K lower than the cold junctions of the top unicouples, but the input thermal powers to the former are the same as those rejected by the latter. Assuming zero side heat losses and a contact resistance of 150 μΩ cm² per leg in the top and bottom unicouples, the calculated peak efficiencies of the CTCs vary from 9.43% to 14.35%. These efficiencies are 40–113% higher, respectively, than that of SOA SiGe (∼6.5%) when operating at the cold junction temperature of 566 K and the same hot junction temperature (1273 K) and contact resistance per leg. Decreasing this resistance to a realistic value of 50 μΩ cm² per leg increases the peak efficiencies of the CTCs by 0.5–0.9 percentage points to 9.93–15.25%.     

Detailed study of the impact of co-utilization of biomass in a natural gas combined cycle power plant through perturbation analysis

Co-utilization of fossil fuels and biomass is a successful way to make efficient use of biomass for power production. When replacing only a limited amount of fossil fuel by biomass, measurements of net output power and input fuel rates will however not suffice to accurately determine the marginal efficiency of the newly introduced alternative fuel. The present paper therefore proposes a technique to determine the marginal biomass efficiency with more accuracy. The process simulation model for co-utilization of natural gas and a small perturbing fraction of biomass in an existing combined cycle plant (500 MW_th Drogenbos, Belgium) is taken as case study. In this particular plant, biomass is introduced into the cycle as fuel for a primary steam reforming process of the input natural gas.     

Packed-bed thermal storage for concentrated solar power – Pilot-scale demonstration and industrial-scale design

A thermal energy storage system, consisting of a packed bed of rocks as storing material and air as high-temperature heat transfer fluid, is analyzed for concentrated solar power (CSP) applications. A 6.5 MWh_th pilot-scale thermal storage unit immersed in the ground and of truncated conical shape is fabricated and experimentally demonstrated to generate thermoclines. A dynamic numerical heat transfer model is formulated for separate fluid and solid phases and variable thermo-physical properties in the range of 20–650 °C, and validated with experimental results. The validated model is further applied to design and simulate an array of two industrial-scale thermal storage units, each of 7.2 GWh_th capacity, for a 26 MW_el round-the-clock concentrated solar power plant during multiple 8 h-charging/16 h-discharging cycles, yielding 95% overall thermal efficiency.     

Effects of preheating vegetable oils on performance and emission characteristics of two diesel engines

Performance and emission characteristics of vegetable oils at elevated temperatures are studied. Fuels are run in two four-cycle, direct injection compression ignited engines having different number of cylinders, compression ratios, rated power and cooling systems but relatively close engine speed. Brake thermal efficiency, exhaust gas temperature, and CO, O₂, Unburned HC and NO emissions are determined as a function of load at ambient and preheat conditions for peanut, sunflower and canola oils. Overall, effects of preheat, engine type and type of vegetable oils on engine performance and exhaust gas emissions are discussed.     

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.     

Prediction of the heat flux profile on the furnace wall of circulating fluidized bed boilers

The purpose of this work is to investigate and develop a correlation for predicting the profile of heat flux on the crest of the membrane water wall tube along the height of circulating fluidized bed furnaces. The heat conduction equation for the tube was solved numerically under various operating conditions and furnace sizes. It was found that the temperature and heat flux profiles decreased rapidly in the region above the secondary air ports and then were found to be nearly constant. In addition, the heat flux increased as the Froude number increased or as the bed particle to the furnace diameter ratio decreased. The results were used to develop a correlation for predicting the heat flux profiles of the boilers having capacities from 12 MW_th to 165 MW_th in terms of dimensionless temperature, the Froude number, the diameter ratio and the height from the ports to the total height ratio.     

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.     

Combustion and NOx emission characteristics of a retrofitted down-fired 660 MWe utility boiler at different loads

Industrial experiments were performed for a retrofitted 660 MW_e full-scale down-fired boiler. Measurements of ignition of the primary air/fuel mixture flow, the gas temperature distribution of the furnace and the gas components in the furnace were conducted at loads of 660, 550 and 330 MW_e. With decreasing load, the gas temperature decreases and the ignition position of the primary coal/air flow becomes farther along the axis of the fuel-rich pipe in the burner region under the arches. The furnace temperature also decreases with decreasing load, as does the difference between the temperatures in the burning region and the lower position of the burnout region. With decreasing load, the exhaust gas temperature decreases from 129.8 °C to 114.3 °C, while NO_x emissions decrease from 2448 to 1610 mg/m³. All three loads result in low carbon content in fly ash and great boiler thermal efficiency higher than 92%. Compared with the case of 660 MW_e before retrofit, the exhaust gas temperature decreased from 136 to 129.8 °C, the carbon content in the fly ash decreased from 9.55% to 2.43% and the boiler efficiency increased from 84.54% to 93.66%.