Pre-combustion CO2 capture from natural gas power plants,with ATR and MDEA processes

Among the various configurations of fossil fuel power plants with carbon capture, this paper focuses on pre-combustion techniques applied to natural gas combined cycles. With more detail, the plant configuration here addressed includes: (i) the steam reforming of natural gas, based on an air-blown autothermal process, following a recuperative pre-reforming treatment, (ii) the water gas shift producing CO₂ and H₂, (iii) the separation of CO₂ by means of a mixed physical–chemical absorption system using a MDEA solution, and (iv) a hydrogen fuelled combined cycle.Similar configurations have been studied quite extensively, being among the most attractive for full-scale realizations in a near-mid term future. This paper proposes a detailed thermodynamic study and optimization of the plant configuration, bringing to a reliable performance estimation based on today's best available technology as far as the various plant sections are concerned (gas and steam turbine, natural gas reforming process, CO₂ separation). The predicted LHV efficiency for the base configuration is about 50%. Being this value at the top of the range quoted in the open literature studies (35–50%), the paper includes a quite extensive sensitivity analysis, showing that more conservative assumptions may bring to significantly poorer performance, especially considering the pretty large number of operating parameters involved in the process.     

Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plants: Implications for emission and energy management

This work provides the essential information and approaches for integration of carbon dioxide (CO₂) capture units into power plants, particularly the supercritical type, so that energy utilization and CO₂ emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO₂ capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO₂ captured and avoided. The parameters of interest include CO₂ capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO₂ capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO₂ capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO₂ at a higher efficiency to achieve greater CO₂ emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO₂ capture unit should be considered for process integration.     

Techno-economic study of CO2 capture from natural gas based hydrogen plants

Canadian oil sands are considered to be the second largest oil reserves in the world. However, the upgrading of bitumen from oil sands to synthetic crude oil (SCO) requires nearly ten times more hydrogen (H₂) than conventional crude oils. The current H₂ demand for oil sands operations is met mostly by steam reforming of natural gas (SMR). The future expansion of oil sands operations is likely to quadruple the demand of H₂ for oil sand operations in the next decade.This paper presents modified process schemes that capture CO₂ at minimum energy penalty in modern SMR plants. The approach is to simulate a base case H₂ plant without CO₂ capture and then look for the best operating conditions that minimize the energy penalty associated with CO₂ capture while maximizing H₂ production. The two CO₂ capture schemes evaluated in this study include a membrane separation process and the monoethanolamine (MEA) absorption process. A low energy penalty is observed when there is lower CO₂ production and higher steam production. The process simulation results show that the H₂ plant with CO₂ capture has to be operated at lower steam to carbon ratio (S/C), higher inlet temperature of the SMR and lower inlet temperatures for the water gas-shift (WGS) converters to attain lowest energy penalty. Also it is observed that both CO₂ capture processes, the membrane process and the MEA absorption process, are comparable in terms of energy penalty and CO₂ avoided when both are operated at conditions where lowest energy penalty exists.     

Design and off-design analyses of a pre-combustion CO2 capture process in a natural gas combined cycle power plant

In this study, a cycle designed for capturing the greenhouse gas CO₂ in a natural gas combined cycle power plant has been analyzed. The process is a pre-combustion CO₂ capture cycle utilizing reforming of natural gas and removal of the carbon in the fuel prior to combustion in the gas turbine. The power cycle consists of a H₂-fired gas turbine and a triple pressure steam cycle. Nitrogen is used as fuel diluent and steam is injected into the flame for additional NO_x control. The heat recovery steam generator includes pre-heating for the various process streams. The pre-combustion cycle consists of an air-blown auto-thermal reformer, water–gas shift reactors, an amine absorption system to separate out the CO₂, as well as a CO₂ compression block. Included in the thermodynamic analysis are design calculations, as well as steady-state off-design calculations. Even though the aim is to operate a plant, as the one in this study, at full load there is also a need to be able to operate at part load, meaning off-design analysis is important. A reference case which excludes the pre-combustion cycle and only consists of the power cycle without CO₂ capture was analyzed at both design and off-design conditions for comparison. A high degree of process integration is present in the cycle studied. This can be advantageous from an efficiency stand-point but the complexity of the plant increases. The part load calculations is one way of investigating how flexible the plant is to off-design conditions. In the analysis performed, part load behavior is rather good with efficiency reductions from base load operation comparable to the reference combined cycle plant.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

Electric Swing Adsorption for CO2 removal from flue gases

One of the most important sources of CO₂ emissions are the fossil-fuel fired plants for production of electricity. Removal of CO₂ from flue gas streams for further sequestration has been proposed by the International Panel on Climate Change experts as one of the most reliable solutions to mitigate anthropogenic greenhouse emissions. When natural gas is employed as fuel, the molar fraction of CO₂ in the flue gas is lower than 5% causing serious problems for capture. The purpose of this work is to present experimental validation of an Electric Swing Adsorption (ESA) technology that may be employed for carbon capture for low molar fractions of CO₂ in the flue gas streams. To improve energy utilization, an activated carbon honeycomb monolith with low electrical resistivity was employed as selective adsorbent. A mathematical model for this honeycomb is proposed as well as different ESA cycles for CO₂ capture.     

Reforming of CO2-containing natural gas with steam in AC gliding arc discharge for hydrogen production

In this study, a low-temperature gliding arc discharge system was used to investigate the effects of steam content and operational parameters, i.e. total feed flow rate, applied voltage, and input frequency, on the reforming performance of CO₂-containing natural gas. The addition of steam less than 10% was found to enhance both selectivities for hydrogen and carbon monoxide with a significant reduction of power consumptions. The highest hydrogen selectivity and yield with the lowest power consumptions were achieved at a steam content of 10 mol%, a total feed flow rate of 100 cm³/min (corresponding to a very short residence time of 1.37 s), an applied voltage of 13.5 kV and an input frequency of 300 Hz. Under these optimum conditions, the oxidative dehydrogenation reactions to produce hydrogen were dominant with the minimum activities of all undesired reactions of cracking and coupling. Both of the short residence time (1.37 s) with a low bulk temperature (lower than 200°C) in the plasma zone under atmospheric pressure, indicate that the studied plasma reactor (gliding arc system) is superior to conventional catalytic reactors for reforming of natural gas.     

Processing of Straw/Corn Stover: Comparison of Life Cycle Emissions

The LCA emissions from four renewable energy routes that convert straw/corn stover into usable energy are examined. The conversion options studied are ethanol by fermentation, syndiesel by oxygen gasification followed by Fischer Tropsch synthesis, and electricity by either direct combustion or biomass integrated gasification and combined cycle (BIGCC). The greenhouse gas (GHG) emissions of these four options are evaluated, drawing on a range of studies, and compared to the conventional technology they would replace in a western North American setting. The net avoided GHG emissions for the four energy conversion processes calculated relative to a “business as usual” case are 830 g CO₂e/kWh for direct combustion, 839 g CO₂e/kWh for BIGCC, 2,060 g CO₂e/L for ethanol production, and 2,440 g CO₂e/L for FT synthesis of syndiesel. The largest impact on avoided emissions arises from substitution of biomass for fossil fuel. Relative to this, the impact of emissions from processing of fossil fuel, e.g., refining of oil to produce gasoline or diesel, and processing of biomass to produce electricity or transportation fuels, is minor.     

Effective retrofitting of post-combustion CO2 capture to coal-fired power plants and insensitivity of CO2 abatement costs to base plant efficiency

Existing coal-fired power plants were not designed to be retrofitted with carbon dioxide post-combustion capture (PCC) and have tended to be disregarded as suitable candidates for carbon capture and storage on the grounds that such a retrofit would be uneconomical. Low plant efficiency and poor performance with capture compared to new-build projects are often cited as critical barriers to capture retrofit. Steam turbine retrofit solutions are presented that can achieve effective thermodynamic integration between a post-combustion CO₂ capture plant and associated CO₂ compressors and the steam cycle of an existing retrofitted unit for a wide range of initial steam turbine designs. The relative merits of these capture retrofit integration options with respect to flexibility of the capture system and solvent upgradability will be discussed. Provided that effective capture system integration can be achieved, it can be shown that the abatement costs (or cost per tonne of CO₂ to justify capture) for retrofitting existing units is independent of the initial plant efficiency. This then means that a greater number of existing power plants are potentially suitable for successful retrofits of post-combustion capture to reduce power sector emissions. Such a wider choice of retrofit sites would also give greater scope to exploit favourable site-specific conditions for CCS, such as ready access to geological storage.     

Derivation of correlations to evaluate the impact of retrofitted post-combustion CO2 capture processes on steam power plant performance

When integrating a post-combustion CO₂ capture process and CO₂ compression into a steam power plant, the three interface quantities heat, electricity and cooling duty must be satisfied by the power plant, leading to a loss in net efficiency. The heat duty shows to be the largest contributor to the overall net efficiency penalty of the power plant. Additional energy penalty results from the cooling and electric power duty of the capture and compression units.In this work, the dependency of the energy penalty on the quantity and quality of the heat duty is analyzed and quantified for a state-of-the-art hard coal fired power plant. Furthermore, the energy penalty attributed to the additional cooling and power duty is quantified. As a result correlations are provided which enable to predict the impact of the heat, cooling and electricity duty of post-combustion CO₂ capture processes on the net output of a steam power plant in a holistic approach.     

Greenhouse gas Emissions projections and mitigation options for the Czech Republic, 1990–2010

The models used to assess greenhouse gas mitigation options for the Czech Republic are discussed and compared with respect to their capabilities and ease of use. The input data and preliminary results are described. According to the projections, Czech CO₂ emissions will not exceed their 1990 level until 2010. Assessment of several mitigation options shows that a 6% reduction in CO₂ emissions can be achieved using cost-effective technologies. Key areas for mitigation measures are fuel switching from brown coal to natural gas through replacement of boilers, efficiency improvements in household heating, and use of compact fluorescent lamps.     

Greenhouse gas Emissions projections and mitigation options for the Czech Republic, 1990–2010

The models used to assess greenhouse gas mitigation options for the Czech Republic are discussed and compared with respect to their capabilities and ease of use. The input data and preliminary results are described. According to the projections, Czech CO₂ emissions will not exceed their 1990 level until 2010. Assessment of several mitigation options shows that a 6% reduction in CO₂ emissions can be achieved using cost-effective technologies. Key areas for mitigation measures are fuel switching from brown coal to natural gas through replacement of boilers, efficiency improvements in household heating, and use of compact fluorescent lamps.

     

Alternative energy balances for Bulgaria to mitigate climate change

Alternative energy balances aimed to mitigate greenhouse gas (GHG) emissions are developed as alternatives to the baseline energy balance. The section of mitigation options is based on the results of the GHG emission inventory for the 1987–1992 period. The energy sector is the main contributor to the total CO₂ emissions of Bulgaria. Stationary combustion for heat and electricity production as well as direct end-use combustion amounts to 80% of the total emissions. The parts of the energy network that could have the biggest influence on GHG emission reduction are identified. The potential effects of the following mitigation measures are discussed: rehabilitation of the combustion facilities currently in operation; repowering to natural gas; reduction of losses in thermal and electrical transmission and distribution networks; penetration of new combustion technologies; tariff structure improvement; renewable sources for electricity and heat production; wasteheat utilization; and supply of households with natural gas to substitute for electricity in space heating and cooking. The total available and the achievable potentials are estimated and the implementation barriers are discussed.

     

Global Warming Impact of Electricity Generation from Beef Cattle Manure: A Life Cycle Assessment Study

We compare calculated greenhouse gas emissions for a North American beef feedlot operation, which includes biogas production by anaerobic digestion with subsequent electricity generation (the AD case), to the emissions for a “business as usual” case, which includes both a feedlot and an equivalent amount of grid-generated electricity. Anaerobic digestion, biogas production and electricity production are the major sources of differences in emissions. Fertilizer production, crop production, manure collection and spreading, as well as the associated transport stages are also considered within the LCA system boundaries; impacts on life cycle emissions from these sources are lower. Running a feedlot and producing electricity using typical grid power plants produces 3,845 kg CO_2?eq/MWh while running a feedlot, which generates biogas to produce electricity, produces 2,965 kg CO_2?eq/MWh. This savings of 880 kg CO_2?eq/MWh arises because the net power generation in the AD case emits about 90% less life cycle GHG emissions compared to grid-average electricity. The high overall emission levels arise due to emissions associated with enteric fermentation in beef cattle as the main source of GHG emissions in both the “business as usual” and the AD cases. It contributed 57% of total emissions for the feedlot /biogas /electricity system and 44% of total emissions for the feedlot /grid electricity system.     

Life cycle modelling of fossil fuel power generation with post-combustion CO2 capture

Due to its compatibility with the current energy infrastructures and the potential to reduce CO₂ emissions significantly, CO₂ capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO₂ capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO₂ capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO₂ capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO₂ capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO₂ capture, in order to compare the life cycle environmental performance of systems with and without CO₂ capture. The LCA results for the alternative post-combustion CO₂ capture methods (including MEA, K⁺/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO₂ capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.     

Techno-Economic Study of CO2 Capture from an Existing Cement Plant Using MEA Scrubbing

Carbon dioxide is the major greenhouse gas responsible for global warming. Man-made CO₂ emissions contribute approximately 63% of greenhouse gases and the cement industry is responsible for approximately 5% of CO₂ emissions emitting nearly 900 kg of CO₂ per 1000 kg of cement. CO₂ from a cement plant was captured and purified to 98% using the monoethanolamine (MEA) based absorption process. The capture cost was $51 per tonne of CO₂ captured, representing approximately 90% of total cost. Steam was the main operating cost representing 39% of the total capture cost. Switching from coal to natural gas reduces CO₂ emissions by about 18%. At normal load, about 36 MW of waste heat is available for recovery to satisfy the parasitic heat requirements of MEA process; however, it is very difficult to recover.     

Co-production of hydrogen and electricity with CO2 capture

Electricity and hydrogen can be used as energy carriers to reduce emissions of CO₂ from small and mobile energy users. One of the most promising technologies for the production of electricity and hydrogen with low CO₂ emissions is coal gasification with CO₂ capture and storage. Performance and cost data are presented for plants which produce electricity and hydrogen alone and plants which co-produce both of these energy carriers. The co-production plants include plants which produce a fixed ratio of hydrogen to electricity and plants which are able to vary the ratio while continuing to operate the gasification and CO₂ capture parts of the plant at full load. The paper also assesses the ability of these types of plants to satisfy the varying demands for hydrogen and electricity in future energy supply systems. The lowest cost option for the scenarios assessed in the paper is the use of flexible co-production plants with underground buffer storage of hydrogen.     

Assessing the value of CO2 capture ready in new-build pulverised coal-fired power plants in China

Making new plants CO₂ capture ready (CCR) would enable them to retrofit to capture CO₂ at a later date at lower cost when the appropriate policy and/or economic drivers are in place. In order to understand the economic value and investment characteristics of making new plants CCR in China, a typical 600 MW pulverised coal-fired ultra-supercritical power plant, locating in Guangdong province, was examined. Combined with an engineering assessment, costs were estimated for different CCR scenarios. To analyze CCR investment opportunities, the paper applies a cash flow model for valuing capture options and CCR investment. Results were obtained by Monte-Carlo simulation, based on engineering surveys and an IEA GHG CCR study, as well as plant performance information and expert projections on carbon prices, coal prices and electricity prices.CCR investments are justified by factors such as higher retrofitting probabilities, lower early closure probabilities and fair economic return. However, the economic case for CCR largely depends on two factors: (a) whether the original plant is retrofittable without CCR; and (b) the type of investments made, for example, investments essential to CCR tend to be more economic than additional non-essential CCR features such as clutched low pressure turbines. The carbon price and discount rate were found to have significant impacts on the economics of CCR. Overall, it appears that the value of the ‘capture options’ that CCR generates for retrofitting CCS is significant, and so could justify a modest CCR investment, even assuming the original plant is retrofittable without CCR. It was also found the value of CCR might be significantly understated if the range of potential retrofitting dates is artificially constrained.     

Estimating the potential of greenhouse gas mitigation in Kazakhstan

As part of the studies related to the obligations of the UN Framework Convention on Climate Change, the Republic of Kazakhstan started activities to inventory greenhouse gas (GHG) emissions and assess of GHG mitigation options. The objective of this paper is to present an estimate of the possibility of mitigating GHG emissions and determine the mitigation priorities. It presents a compilation of the possible options and their assessment in terms of major criteria and implementation feasibility. Taking into account the structure of GHG emissions in Kazakhstan in 1990, preliminary estimates of the potential for mitigation are presented for eight options for the energy sector and agriculture and forestry sector. The reference scenario prepared by expert assessments assumes a reduction of CO₂ emissions in 1996–1998 by about 26% from the 1990 level due to general economic decline, but then emissions increase. It is estimated that the total potential for the mitigation of CO₂ emissions for the year 2000 is 3% of the CO₂ emissions in the reference scenario. The annual reduction in methane emissions due to the estimated options can amount to 5%–6% of the 1990 level.

     

Steam demand reduction of water–gas shift reaction in IGCC power plants with pre-combustion CO2 capture

This paper presents the results of system assessments that were conducted to compare conventional and advanced water–gas shift reactor sections. The latter are specifically tailored for Integrated Gasification Combined Cycles (IGCC) power plants with pre-combustion CO₂ capture. The advanced shift reactor section comprises four staged reactors with distributed feeds of synthesis gas and quench water in between the reactors. Conventional shift reactor sections consist of two sequential reactors with intermediate cooling, where the entire synthesis gas stream passes both reactors.The advanced shift reactor section reduces the steam requirement of the water–gas shift reaction up to 70% in comparison with conventional configurations, at carbon dioxide capture ratios of approximately 85%. This reduction allows for lower electric efficiency penalties, thus higher net electric outputs for IGCC power plants with CO₂ capture. For each case, the CO₂ capture ratio was optimised for the lowest specific lost work per amount of captured CO₂. Both the number of reactors and the total catalyst volume are higher for the advanced shift reactor sections, resulting in increased capital expenses. In case of four staged reactors, the additional expenses are expected to be outperformed by the increased revenues associated with the higher net electric output.