Hydrogen no longer a high cost solution to global warming: New ideas

This paper contains brief statements about three new low-cost methods of obtaining clean hydrogen in massive amounts.

In the first method, new technology for converting solar energy and water to hydrogen at a price of $2.50 for an amount of hydrogen equal in first law energy to that in a gallon of gasoline seems to follow from a company's announcement of their new technology, already working, in one fully industrialized plant, producing electricity at a price corresponding to that from coal.

In the second method, pure hydrogen (no accompanying CO₂) can be obtained from natural gas and heat. The cost would be a little less than that of the low-cost hydrogen from water decomposition (and avoid storage of hydrogen for the 18 h/day of zero solar light).

In the third method, CO₂ is extracted from the atmosphere and combined chemically with the low-cost hydrogen to produce methanol. On being used to produce heat or electricity (fuel cell), CO₂ is left over. However, the amount of CO₂, thus added to the atmosphere is just equivalent to the amount removed. The presence of low-cost hydrogen from water means that the resulting methanol will also be of low cost and be a cure for global warming without a radical change of distribution method.     

CO2 sequestration in Ontario, Canada. Part II: cost estimation

As the Kyoto target set for Canada is to reduce GHG emission by 6% of the 1990 level by 2008–2012, several options are being considered to achieve this target. One of the possible options in Ontario is geological sequestration of captured CO₂ in saline aquifers, where CO₂ is expected to be stored for long geological periods, from 100 to several thousand years depending on the size, property and location of the reservoir. The preferred concept is to inject CO₂ into a porous and permeable reservoir covered with a cap rock located at least 800 m beneath the earth's surface where CO₂ can be stored under supercritical conditions. This paper evaluates the capital and operating cost for CO₂ sequestration in southwestern Ontario from a 500 MW coal fired power plant. The main focus is on the cost of sequestration (CO₂ transport and injection), and thus, the cost of capturing and pressurizing the CO₂ from the plant flue gas is not considered here.

A significant amount of capital investment is necessary to transfer CO₂ from a 500 MW fossil fuel power plant to the injection location and to store it underground. Major components of the cost include: cost of pipeline, cost of drilling injection wells and installing platforms, since the more plausible injection area is under Lake Erie. Many uncertainties are associated with cost estimation; several are identified and their impacts are considered in this paper. The estimated cost of sequestration of 14,000 ton/day of CO₂ at approximately 110 bar in southwestern Ontario is between 7.5 and 14 US$/ton of CO₂ stored.     

Low-temperature catalytic partial oxidation of hydrocarbons (C1–C10) for hydrogen production

The catalytic partial oxidation of hydrocarbons to provide hydrogen for fuel cells, mobile or stationary, requires high temperatures (900°C), multireactors and incurs the highest incremental costs for the gasoline fuel processor. New experimental data between 500°C and 600°C, supported by equilibrium calculations, show that hydrogen with low carbon monoxide concentrations can be produced from liquid and gaseous hydrocarbons, thus simplifying the reactor chain. Low sulphur refinery feeds (C₄–C₆, C₄–C₁₀), simulated natural gas (C₁–C₃) and single compounds are used and safety procedures discussed. Results from laboratory reactors with 1 wt% rhodium on mixed oxide catalysts show that hydrogen rates of 43,000 lH₂/h/l reactor (power density 129 kWth/l reactor) are produced with RON=95 feeds. However, the cost and availability of rhodium limit the catalyst rhodium content to 0.1 wt% when 31,100 lH₂/h/l reactor were measured. Optimisation and reactor scale-up for heat management is in progress.     

Effects of future fossil fuel use on CO2 levels in the atmosphere

A model based on fossil fuel use per capita and United Nations population predictions has been developed to predict global fossil fuel use and the resulting levels of CO₂ in the atmosphere. The results suggest levels of CO₂ will increase to between 415 and 421 ppm by 2025. Countries with energy-intensive economies will be responsible for the majority of CO₂ emissions, while nations with large populations but low energy consumption per capita will have less of an effect. A major increase in nuclear power generation will not have a significant impact on CO₂ levels over this time scale.     

Evaluation of potential cost reductions from improved amine-based CO2 capture systems

Technological innovations in CO₂ capture and storage technologies are being pursued worldwide under a variety of private and government-sponsored R&D programs. While much of this R&D is directed at novel concepts and potential breakthrough technologies, there are also substantial efforts to improve CO₂ capture technologies already in use. In this paper, we focus on amine-based CO₂ capture systems for power plants and other combustion-based applications. The current performance and cost of such systems have been documented in several recent studies. In this paper we examine the potential for future cost reductions that may result from continued process development. We used the formal methods of expert elicitation to understand what experts in this field believe about possible improvements in some of the key underlying parameters that govern the performance and cost of this technology. A dozen leading experts from North America, Europe and Asia participated in this study, providing their probabilistic judgments via a detailed questionnaire coupled with individual interviews. Judgments about detailed technical parameters were then used in an integrated power plant modeling framework (IECM-CS) developed for USDOE to evaluate the performance and costs of alternative carbon capture and sequestration technologies for fossil-fueled power plants. The experts’ responses have allowed us to build a picture of how the overall performance and cost of amine-based systems might improve over the next decade or two. Results show how much the cost of CO₂ capture could be reduced via targeted R&D in key areas.     

Cost effective integration of hydrogen in energy systems with CO2 constraints

The integration of hydrogen in national energy systems is illustrated in four extreme scenarios, reflecting four technological mainstreams (energy conservation, renewables, nuclear and CO₂ removal) to reduce C emissions. Hydrogen is cost-effective in all scenarios with higher CO₂ reduction targets. Hydrogen would be produced from fossil fuels, or from water and electricity or heat, depending upon the scenario. Hydrogen would be used in the residential and commercial sectors and for transport vehicles, industry, and electricity generation in fuel cells. At severe (50–70%) CO₂ reduction targets, hydrogen would cost-effectively supply more than half of the total useful energy demands in three out of four scenarios. The marginal emission reduction costs in the CO₂ removal scenario at severe CO₂ reduction targets are DFL 200/tCO₂ (ca $ 100/t). In the nuclear, renewable and energy conservation scenarios these costs are much higher. Whilst the fossil fuel scenario would be less expensive than the other scenarios, the possibility of CO₂ storage in depleted gas reservoirs is a conditio sine qua non.     

Multi-objective optimization of molten carbonate fuel cell system for reducing CO2 emission from exhaust gases

The aim of this paper is to investigate the implementation of a molten carbonate fuel cell (MCFC) as a CO₂ separator. By applying multi-objective optimization (MOO) using the genetic algorithm, the optimal values of operating load and the corresponding values of objective functions are obtained. Objective functions are minimization of the cost of electricity (COE) and minimization of CO₂ emission rate. CO₂ tax that is accounted as the pollution-related cost, transforming the environmental objective to the cost function. The results show that the MCFC stack which is fed by the syngas and gas turbine exhaust, not only reduces CO₂ emission rate, but also produces electricity and reduces environmental cost of the system.     

新能源制氢在传统炼化企业的应用

目的   化石燃料和新能源电力在使用和发展中面临着问题与挑战。为解决传统炼化企业依赖化石燃料制氢中的碳排放问题,和新能源电力发展中的波动性问题提供建议,有必要对氢气制备技术的应用与发展,和传统炼化企业的氢气网络状况进行梳理。 方法   调研了氢气制备技术的应用与发展,尤其关注了关键技术电解水制氢技术的应用发展;分氢制备、氢使用、氢纯化三部分对传统炼化企业的氢气网络进行了深入剖析。 结果   通过总结,提出通过电解水制氢技术将富余的新能源电力与传统炼化企业氢网络相结合的设想。在传统炼化企业附近布置新能源电给,不但可以供炼厂日常用电,还可将因波动性大而无法直接利用的弃电部分,直接通过电解水制氢技术,制氢供传统炼化企业使用,有效降低传统炼化企业的碳排放强度。 结论   要解决化石燃料使用中的碳排放问题与新能源电力使用中波动性高的问题,实现新能源制氢在传统炼化企业的应用,还面临着诸多挑战。     

Performance modelling of a carbon dioxide removal system for power plants

In this paper, a carbon dioxide removal and liquefaction system, which separates carbon dioxide from the flue gases of conventional power plants, was modelled. The system is based on an amine chemical absorption stripping system, followed by a liquefaction unit to treat the removed CO₂ for transportation and storage. The effect of the main parameters on the absorption and stripping columns is presented. The main constraints set for the model are a capture efficiency of 90% and the use of an aqueous solution with a maximum 30% amine content by weight. The goal of this study is to remove the CO₂ with minimum energy requirements for the process when it is integrated in a fossil fuel fired power plant. Results of the simulation are compared to experimental and literature data from feasibility studies and existing plants.

The power plant to which the removal system is connected is a 320 MW steam power plant with steam reheat and 8 feedwater heaters. Two different fossil fuels were considered: coal and natural gas. The effect of the modifications necessary to integrate the CO₂ removal system in the power plant is also studied.

The capital cost of the removal and liquefaction system is estimated, and its influence on the cost of generated electricity is calculated.     

Environmental assessment and extended exergy analysis of a “zero CO2 emission”, high-efficiency steam power plant

Aim of this paper is to analyze the performance of an innovative high-efficiency steam power plant by means of two “life cycle approach” methodologies, the life cycle assessment (LCA) and the “extended exergy analysis” (EEA).

The plant object of the analysis is a hydrogen-fed steam power plant in which the H₂ is produced by a “zero CO₂ emission” coal gasification process (the ZECOTECH^© cycle). The CO₂ capture system is a standard humid-CaO absorbing process and produces CaCO₃ as a by-product, which is then regenerated to CaO releasing the CO₂ for a downstream mineral sequestration process.

The steam power plant is based on an innovative combined-cycle process: the hydrogen is used as a fuel to produce high-temperature, medium-pressure steam that powers the steam turbine in the topping section, whose exhaust is used in a heat recovery boiler to feed a traditional steam power plant.

The environmental performance of the ZECOTECH^© cycle is assessed by comparison with four different processes: power plant fed by H₂ from natural gas steam reforming, two conventional coal- and natural gas power plants and a wind power plant.     

Prediction of cost and emission from Indian coal-fired power plants with CO2 capture and storage using artificial intelligence techniques

Coal-fired power plants are one of the most important targets with respect to reduction of CO₂ emissions. The reasons for this are that coal-fired power plants offer localized large point sources (LPS) of CO₂ and that the Indian power sector contributes to roughly half of all-India CO₂ emissions. CO₂ capture and storage (CCS) can be implemented in these power plants for long-term decarbonisation of the Indian economy. In this paper, two artificial intelligence (AI) techniques—adaptive network based fuzzy inference system (ANFIS) and multi gene genetic programming (MGGP) are used to model Indian coal-fired power plants with CO₂ capture. The data set of 75 power plants take the plant size, the capture type, the load and the CO₂ emission as the input and the COE and annual CO₂ emissions as the output. It is found that MGGP is more suited to these applications with an R² value of more than 99% between the predicted and actual values, as against the ~96% correlation for the ANFIS approach. MGGP also gives the traditionally expected results in sensitivity analysis, which ANFIS fails to give. Several other parameters in the base plant and CO₂ capture unit may be included in similar studies to give a more accurate result. This is because MGGP gives a better perspective toward qualitative data, such as capture type, as compared to ANFIS.     

A comparison of electricity and hydrogen production systems with CO2 capture and storage—Part B: Chain analysis of promising CCS options

Promising electricity and hydrogen production chains with CO₂ capture, transport and storage (CCS) and energy carrier transmission, distribution and end-use are analysed to assess (avoided) CO₂ emissions, energy production costs and CO₂ mitigation costs. For electricity chains, the performance is dominated by the impact of CO₂ capture, increasing electricity production costs with 10–40% up to 4.5–6.5 €ct/kWh. CO₂ transport and storage in depleted gas fields or aquifers typically add another 0.1–1 €ct/kWh for transport distances between 0 and 200 km. The impact of CCS on hydrogen costs is small. Production and supply costs range from circa 8 €/GJ for the minimal infrastructure variant in which hydrogen is delivered to CHP units, up to 20 €/GJ for supply to households. Hydrogen costs for the transport sector are between 14 and 16 €/GJ for advanced large-scale coal gasification units and reformers, and over 20 €/GJ for decentralised membrane reformers. Although the CO₂ price required to induce CCS in hydrogen production is low in comparison to most electricity production options, electricity production with CCS generally deserves preference as CO₂ mitigation option. Replacing natural gas or gasoline for hydrogen produced with CCS results in mitigation costs over 100 €/t CO₂, whereas CO₂ in the power sector could be reduced for costs below 60 €/t CO₂ avoided.     

The design of long-life,high-efficiency PEM fuel cell power supplies for low power sensor networks

Field sensor networks have important applications in environmental monitoring, wildlife preservation, in disaster monitoring and in border security. The reduced cost of electronics, sensors and actuators make it possible to deploy hundreds if not thousands of these sensor modules. However, power technology has not kept pace. Current power supply technologies such as batteries limit many applications due to their low specific energy. Photovoltaics typically requires large bulky panels and is dependent on varying solar insolation and therefore requires backup power sources. Polymer Electrolyte Membrane (PEM) fuel cells are a promising alternative, because they are clean, quiet and operate at high efficiencies. However, challenges remain in achieving long lives due to factors such as degradation and hydrogen storage. In this work, we devise a framework for designing fuel cells power supplies for field sensor networks. This design framework utilize lithium hydride hydrogen storage technology that offers high energy density of up to 5000 Wh/kg. Using this design framework, we identify operating conditions to maximize the life of the power supply, meet the required power output and minimize fuel consumption. We devise a series of controllers to achieve this capability and demonstrate it using a bench-top experiment that operated for 5000 h. The laboratory experiments point towards a pathway to demonstrate these fuel cell power supplies in the field. Our studies show that the proposed PEM fuel cell hybrid system fueled using lithium hydride offers at least a 3 fold reduction in mass compared to state-of-the-art batteries and 3-5 fold reduction in mass compared to current fuel cell technologies.     

Combustion technology developments in power generation in response to environmental challenges

Combustion system development in power generation is discussed ranging from the pre-environmental era in which the objectives were complete combustion with a minimum of excess air and the capability of scale up to increased boiler unit performances, through the environmental era (1970–), in which reduction of combustion generated pollution was gaining increasing importance, to the present and near future in which a combination of clean combustion and high thermodynamic efficiency is considered to be necessary to satisfy demands for CO₂ emissions mitigation.

From the 1970s on, attention has increasingly turned towards emission control technologies for the reduction of oxides of nitrogen and sulfur, the so-called acid rain precursors. By a better understanding of the NO_x formation and destruction mechanisms in flames, it has become possible to reduce significantly their emissions via combustion process modifications, e.g. by maintaining sequentially fuel-rich and fuel-lean combustion zones in a burner flame or in the combustion chamber, or by injecting a hydrocarbon rich fuel into the NO_x bearing combustion products of a primary fuel such as coal.

Sulfur capture in the combustion process proved to be more difficult because calcium sulfate, the reaction product of SO₂ and additive lime, is unstable at the high temperature of pulverized coal combustion. It is possible to retain sulfur by the application of fluidized combustion in which coal burns at much reduced combustion temperatures. Fluidized bed combustion is, however, primarily intended for the utilization of low grade, low volatile coals in smaller capacity units, which leaves the task of sulfur capture for the majority of coal fired boilers to flue gas desulfurization.

During the last decade, several new factors emerged which influenced the development of combustion for power generation. CO₂ emission control is gaining increasing acceptance as a result of the international greenhouse gas debate. This is adding the task of raising the thermodynamic efficiency of the power generating cycle to the existing demands for reduced pollutant emission. Reassessments of the long-term availability of natural gas, and the development of low NO_x and highly efficient gas turbine–steam combined cycles made this mode of power generation greatly attractive also for base load operation.

However, the real prize and challenge of power generation R&D remains to be the development of highly efficient and clean coal-fired systems. The most promising of these include pulverized coal combustion in a supercritical steam boiler, pressurized fluid bed combustion without or with topping combustion, air heater gas turbine-steam combined cycle, and integrated gasification combined cycle. In the longer term, catalytic combustion in gas turbines and coal gasification-fuel cell systems hold out promise for even lower emissions and higher thermodynamic cycle efficiency. The present state of these advanced power-generating cycles together with their potential for application in the near future is discussed, and the key role of combustion science and technology as a guide in their continuing development highlighted.     

Solar energy in photosynthesis

Solar energy provides the reducing power within green leaves to convert CO₂ and H₂O into sugars. The CO₂ is supplied by the atmosphere and enters the leaf by diffusion. Factors affecting the rate of photosynthesis must either change the CO₂ diffusive resistances or the CO₂ concentration gradient along the diffusion pathways. Therefore, these effects can be described in terms of diffusive control mechanisms.

Light affects CO₂ diffusion by initiating photosynthesis, which removes CO₂ at the chloroplast and establishes a diffusion gradient. Light also triggers stomatal opening, thereby sharply decreasing the diffusive resistance. However, intense radiation can cause desiccation of stomatal guard cells, a mechanism whereby the diffusive resistance increases.

During illumination, leaf cells have both a source (respiration) and sink (photosynthesis) for CO₂. Respiration in some species appears to be greatly stimulated by light. This additional internal CO₂ flux is a possible reason for a lower efficiency of energy utilization than in species whose respiration is not enhanced by light.

Physiological growth responses or movements often occur that position leaves in the light. Plants lacking this capability are often excluded in ecological succession in nature.     

System analysis of hydrogen production from gasified black liquor

Hydrogen produced from renewable biofuel is both clean and CO₂ neutral. This paper evaluates energy and net CO₂ emissions consequences of integration of hydrogen production from gasified black liquor in a chemical pulp mill. A model of hydrogen production from gasified black liquor was developed and integration possibilities with the pulp mill's energy system were evaluated in order to maximize energy recovery. The potential hydrogen production is 59 000 tonnes per year if integrated with the KAM reference market pulp mill producing 630 000 Air dried tonnes (ADt) pulp/year. Changes of net CO₂ emissions associated with modified mill electric power balance, biofuel import and end usage of the produced hydrogen are presented and compared with other uses of gasified black liquor such as electricity production and methanol production. Hydrogen production will result in the greatest reduction of net CO₂ emissions and could reduce the Swedish CO₂ emissions by 8% if implemented in all chemical market pulp mills. The associated increases of biofuel and electric power consumption are 5% and 1.7%, respectively.     

Thermo-economic analysis of a direct supercritical CO2 electric power generation system using geothermal heat

A comprehensive thermo-economic model combining a geothermal heat mining system and a direct supercritical CO₂ turbine expansion electric power generation system was proposed in this paper. Assisted by this integrated model, thermo-economic and optimization analyses for the key design parameters of the whole system including the geothermal well pattern and operational conditions were performed to obtain a minimal levelized cost of electricity (LCOE). Specifically, in geothermal heat extraction simulation, an integrated wellbore-reservoir system model (T2Well/ECO2N) was used to generate a database for creating a fast, predictive, and compatible geothermal heat mining model by employing a response surface methodology. A parametric study was conducted to demonstrate the impact of turbine discharge pressure, injection and production well distance, CO₂ injection flowrate, CO₂ injection temperature, and monitored production well bottom pressure on LCOE, system thermal efficiency, and capital cost. It was found that for a 100 MW_e power plant, a minimal LCOE of $0.177/kWh was achieved for a 20-year steady operation without considering CO₂ sequestration credit. In addition, when CO₂ sequestration credit is $1.00/t, an LCOE breakeven point compared to a conventional geothermal power plant is achieved and a breakpoint for generating electric power generation at no cost was achieved for a sequestration credit of $2.05/t.     

Pem fuel cells for transportation and stationary power generation applications

We describe recent activities at Los Alamos National Laboratory devoted to polymer electrolyte fuel cells in the contexts of stationary power generation and transportation applications. A low cost/high performance hydrogen or reformate/air stack technology is being developed based on ultra-low platinum loadings and non-machined, inexpensive elements for flow-fields and bipolar plates. On-board methanol reforming is compared to the option of direct methanol fuel cells in light of recent significant power density increases demonstrated in the latter.     

Hydrogen from natural gas without release of CO2 to the atmosphere

The “Hydrogen economy”, in which hydrogen will be a main carrier of energy from renewable sources, is a long term prospect. In the near and medium term increasing demand for hydrogen--also as an energy carrier in special niches--will probably be covered by hydrogen from fossil sources, mainly natural gas. This can be acceptable from an environment as well as an economical point of view, since hydrogen can be produced from natural gas at acceptable costs, without release of CO₂ to the atmosphere. There are two main options for this: (1) hydrogen from natural gas by conventional technology (e.g. steam reforming) including CO₂ sequestration; (2) high temperature pyrolysis of natural gas, yielding pure hydrogen and carbon black. Technologies for industrial scale realisation of these options have been developed and evaluated in Norway, which is a large producer and exporter of natural gas. The economy and market opportunities are discussed in the paper. It appears that renewable energy costs must come down considerably from present levels before hydrogen from renewables can compete with hydrogen from natural gas without release of CO₂ to the atmosphere.     

A coal-fired power plant integrated with biomass co-firing and CO2 capture for zero carbon emission

A promising scheme for coal-fired power plants in which biomass co-firing and carbon dioxide capture technologies are adopted and the low-temperature waste heat from the CO₂ capture process is recycled to heat the condensed water to achieve zero carbon emission is proposed in this paper. Based on a 660 MW supercritical coal-fired power plant, the thermal performance, emission performance, and economic performance of the proposed scheme are evaluated. In addition, a sensitivity analysis is conducted to show the effects of several key parameters on the performance of the proposed system. The results show that when the biomass mass mixing ratio is 15.40% and the CO₂ capture rate is 90%, the CO₂ emission of the coal-fired power plant can reach zero, indicating that the technical route proposed in this paper can indeed achieve zero carbon emission in coal-fired power plants. The net thermal efficiency decreases by 10.31%, due to the huge energy consumption of the CO₂ capture unit. Besides, the cost of electricity (COE) and the cost of CO₂ avoided (COA) of the proposed system are 80.37 $/MWh and 41.63 $/tCO₂, respectively. The sensitivity analysis demonstrates that with the energy consumption of the reboiler decreasing from 3.22 GJ/tCO₂ to 2.40 GJ/ tCO₂, the efficiency penalty is reduced to 8.67%. This paper may provide reference for promoting the early realization of carbon neutrality in the power generation industry.