Carbon Dioxide Capture and Storage in the Nitrogen Syngas Industries

February 13, 2018 | Author: adav1232887 | Category: Natural Gas, Carbon Capture And Storage, Carbon Dioxide, Kyoto Protocol, Coal
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Carbon dioxide capture and storage in the nitrogen and syngas industries Rick Strait and Manoj Nagvekar of KBR Technology look at the options for large-scale syngas producers for carbon capture and storage.

oncern over carbon dioxide emissions and its effect on the environment is peaking worldwide. Ammonia and synthesis gas-based chemical plants are significant generators of carbon dioxide, although not at the same levels as carbon dioxide emitted from power plants. Although there is a great deal of interest in carbon capture and storage (CCS), few in the industry are implementing large-scale CCS projects. KBR Technology discusses some of the obstacles faced when considering a CCS project and what is on the horizon for new and existing synthesis gas-based chemical plants, including ammonia plants.


Background According to the 2008 International Energy Outlook1, total global CO2 emissions were about 28 Gigatonnesin 2005. The CO2 emissions are increasing at a rate of about 1.7% annually and are expected to more than double, reaching about 60 Gigatonnes/yr by 2050. CO2 emissions from large fixed sources, which theoretically could be captured, account for 15 Gigatonnes/yr2. An overwhelming majority (80%) of these emissions are from power plants. Total emissions from the industrial sector, including its share of power consumption, amount to about 11 Gigatonnes/yr. Within the chemical industry, the three largest sources of CO2 emissions are from the production of ethylene and other petrochemicals, ammo-

nia for nitrogen-based fertilizers, and chlorine. It is estimated3 that the fertilizer industry uses about 1.2% of world energy consumption and is responsible for about the same share of global CO2 emissions. It may therefore appear that, in the global picture, the fertilizer industry is a minor contributor to CO2 emissions. As a result of improvements in energy efficiency, the use of natural gas as the primary feedstock, and industry restructuring which drives less efficient producers out of the market, there is not a significant scope for additional reductions in energy consumption and associated CO2 emissions. (China is a major exception since two-thirds of its ammonia production is based on coal). Notwithstanding, all of the successes in reducing energy usage, the industry will be required to comply and take additional steps when global emissions reduction regulations are introduced.

Carbon capture and storage mandates The Kyoto Protocol set binding targets for 37 industrialised countries and the European Union for reducing greenhouse gas (GHG) emissions. The post-Kyoto framework, focusing on issues such as the scale of future reductions, improvements to emissions trading and carbon offset mechanisms, was discussed at the UN Climate

Nitrogen+Syngas 303 | January -February 2010

Conference in December 2009, but the Copenhagen accord is not legally binding. Since 2005, the EU has had an annual cap on CO2 emissions from specific industrial sectors so that the EU and individual member countries can attain their Kyoto mandated targets by the year 2012. The EU has also established a goal of a 20% reduction in CO2 emissions by 2020 as compared to 1990 levels. The European Fertilizer Manufacturers Association (EFMA) has estimated4 that prices in the European nitrogen fertilizer industry will increase by 21-34% in order to compensate for an increase of 30-48% in the production cost due to an estimated CO2 price of 30-50 per tonne from 2013 to 2020. EFMA, while supporting the EU’s goal to reduce emissions 20% by 2020, has concluded that unless granted free emission allowances, the European fertilizer industr y in general will be unable to maintain its competitiveness with non-regulated producers.

Ammonia plant emissions Figure 1 shows the primary sources of CO2 emissions in the typical ammonia plant. In a recent 2,000 metric tonne per day ammonia plant design producing 660,000 t/a of ammonia, the CO2 stripper vent emits 812,000 t/a and the primary reformer stack emits 421,000 t/a. The combined total of the CO2 emissions from the strip-



Fig 1: CO2 Emission Sources in a Typical Ammonia Plant CO2 in flue gas

CO2 air

primary reformer

secondary reformer

feed & steam

per vent and primary reformer stack equals 1.23 million t/a or a ratio of 1.87 tonnes of CO2 per tonne of ammonia produced. Ammonia plants using coal produce the most CO2 emissions while those using natural gas produce the least. Heavier feedstocks containing ethane, propane, butane, pentane etc. produce more CO2 than the example used above. Alternative feedstocks such as oil, petcoke or coal result in even greater amounts of CO2. Even among plants using the same feedstock type there are differences in CO2 emissions. The natural gas used in the example above contains 98.23% methane and 0.16% CO2. Some natural gas contains very significant amounts of CO2 to start with such as one plant in China which uses natural gas containing 20.7% CO2.

Options for CCS As shown in Figure 2, there are different types of CO2 capture systems: post-combustion, pre-combustion, and oxyfuel combustion. The concentration of CO2 in the gas stream, the pressure of the gas stream, and the fuel type (solid or gas) are important factors in selecting the capture system.

Post-combustion capture Post-combustion capture of CO2 from the flue gas of power plants can be economically feasible under specific conditions. Despite many well planned national and international programs, and the existence of some pilot and demonstration plants, there is no full-scale demonstration plant yet for post-combustion CO2 capture from power plants. The two biggest hurdles for post-combustion capture are the significant energy requirements for solvent regeneration and large equipment sizes that are


shift & CO2 removal

to fuel

methanation & dryers


purge gas recovery

magnetite synthesis

NH3 product

loop purge

both due to the relatively low concentrations and partial pressures of CO2 in the flue gas, which is essentially at atmospheric pressure. In the case of a power plant with post-combustion capture, the energy required for solvent regeneration and CO2 compression could represent anywhere from 25 to 35% of its output. Amines, or strictly speaking alkanolamines, are the most frequently used solvents for post-combustion CO2 capture with monoethanolamine (MEA) as the typical benchmark. Proprietary solvents, mostly based on MEA, have been developed by several solvent technology vendors. The goal of these efforts is to improve the solvent reactivity, reduce thermal degradation and, most importantly, reduce the energy consumed for solvent regeneration. For ammonia we refer to the reformer stack as being a difficult location for CO2 capture because it is a post-combustion stream. As mentioned earlier, post-combustion streams are difficult to deal with because the stream is generally at atmospheric pressure and diluted with about 80% nitrogen from the combustion air. This results in a very low partial pressure of CO2, large volumetric flow of solvents, and large absorbers, strippers, circulating pumps, and intercoolers. The net effect is expensive CO2 removal systems consuming large quantities of energy for solvent circulation and stripping steam. Of particular relevance to the fertilizer industry are the post-combustion CO2 capture projects executed by Mitsubishi Heavy Industries (MHI). The CO2 contained in the flue gas emitted from the primary reformer during the ammonia production process is absorbed into the KS-1 proprietary solvent, which MHI jointly developed with Kansai Electric Power Company, Inc (Kansai EP). The CO2 is then synthesized with ammonia

for use as feedstock for urea production. The projects have ranged in size from about 200 to 450 tonnes CO2/day which would still be regarded as about one-eighth the size of a large-scale (1 million tonnes/year) CO2 capture project.

Pre-combustion capture The technology required for pre-combustion capture is widely applied in fertilizer manufacturing and in hydrogen production. For the power industry, the typical application for pre-combustion capture would be an Integrated Gasification Combined Cycle (IGCC) plant where some of the CO2 is removed from the fuel stream before combustion in a gas turbine. The process involves gasification or steam reforming followed by shifting the syngas to produce H2 and CO2. The feedstock could be from a variety of fuels including coal, natural gas, biomass, etc. Depending upon the conditions, the CO2 concentration in the syngas could range from 15-60% and a physical solvent could be used for separation. The syngas processing steps are those that one would employ for H2 production or conversion to Fischer-Tropsch (FT) fuels. Following CO2 capture, the hydrogen-rich syngas is combusted in the gas turbine and the exhaust is now mostly water vapour. Although the initial fuel conversion steps of pre-combustion are more elaborate and costly, the higher concentrations of CO2 in the gas stream and the higher pressure make the separation and the subsequent compression of CO2 easier than post-combustion. The typical solvents used for pre-combustion capture are either physical (i.e. Selexol and Rectisol) or chemical (i.e. methyldiethanolamine). Unlike the solvents for post-combustion capture, these

Nitrogen+Syngas 303 | January -February 2010


technologies are mature and proven on a large commercial scale. IGCC and CO2 Capture are proven independently but have not operated in an integrated manner. There is no gasificationbased IGCC power plant that recovers CO2. Currently in the US, there are three nonpower gasification facilities that recover and compress CO2. There are, of course, many gasification plants for ammonia which recover CO2 for urea production.

Fig 2: Schematic of CO2 Capture Systems [2] N2 O2 coal gas biomass

coal biomass

gas, oil

Urea production from an ammonia plant is a great way to capture CO2 but it is argued that this is merely relocating the emission from the plant vent to the farmer’s field. Also, if ammonia is produced from coal or a heavy feedstock, the CO2 is typically more than what is needed for urea. Co-location of ammonia facilities with methanol facilities is another way to use CO2 in a merchant product. As with urea, this scheme has the disadvantage that CO2 can end up in the atmosphere when the methanol is used for transportation fuels. But if the methanol is used for polymers and plastics, the CO2 may become captured in the finish product such as with polyolefins. If, however, the CO2 from the ammonia plant has to be captured and stored, the CO2 stripper is a convenient location to collect the CO2. This is commonly done when urea is manufactured. The CO2 is compressed to about 2000 psig and sent to the

CO2 reformer H2 +CO2 sep

power & heat

CO2 compression & dehydration


air separation

process+CO2 sep

raw material

urea plant for processing. In a scheme for CO2 capture and sequestration, the same system is used to dry and compress it before sending it to a pipeline. From there, it is stored underground to recover oil and gas from depleted reserves or into aquifers or geological formations that will hold the CO2 for many years into the future. The greater challenge is capturing the CO2 from the primary reformer stack. This is classic post-combustion capture with the associated issues outlined in the previous section. In the power industry, where extensive studies have been performed, it has been determined that the capital cost of capturing a metric tonne of CO2 in a postcombustion retrofit is about $40/tonne per CO2 avoided5. These same studies also conclude there is an operating cost for steam, cooling water, and electric power amounting to another $30/tonne of CO2 avoided for a total cost of about $70/tonne of CO2 avoided. Experience with post-combustion is limited and no one is capturing all the CO2 emitted from stack gases. A very significant parameter is the stripping energy per tonne of CO2 captured from the stack (postcombustion) which is very high in comparison to the energy to capture CO2 from the synthesis gas (pre-combustion) in an ammonia plant. A technology breakthrough needs to occur to reduce the energy of post-combustion capture of CO2. Research is underway to find better solvents, includ-

Nitrogen+Syngas 303 | January -February 2010

N2O2 power & heat


air air/O2 coal gas biomass

Industrial processes

Applications to ammonia plants


coal gas biomass

Oxyfuel combustion is still in the demonstration phase and uses high purity oxygen. This results in relatively higher CO2 concentrations in the gas stream and, hence, in easier separation of CO2 but at the cost of increased energy requirements in the separation of oxygen from air.

In Figure 2, the ammonia process falls under Industrial Processes. The largest difference between industrial processes and others is that others are generating a fuel, while industrial processes are generating a synthesis gas, which for the most part winds up in the product instead of a vent or stack. The processes for capturing CO2 from industrial applications are well known; in fact, most have been developed in ammonia plants.

air air/O2 stream


Oxyfuel combustion capture

CO2 separation

power & heat



gas, ammonia, steel

ing enzymes and other capture methods such as algae, but none of these have been tested at any sizable scale.

Summary The ammonia industry is in a better position than most, as so much of the ammonia is produced from natural gas and is quite efficient. Typically, CO2 is captured from the syngas and compressed for urea production. Clearly, the industry is also watching developments in biomass, alternate fuels, etc. as part of the shift to nontraditional feedstocks to produce the syngas. If there is legislation requiring further cuts in CO2 emissions, the industry will, however, have to look at the primary reformer stack and this would have a significant impact as the CO2 is difficult to capture and will substantially increase the ■ cost of production.

References 1. International Energy Outlook 2008, Energy Information Administration, U.S. Department of Energy, Washington, D.C. (2008). 2. Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change (IPCC) Special Report (2004). 3. Industry in Climate Change 2007: Mitigation, Fourth Assessment Report of the Intergovernmental Panel on Climate Change (2007). 4. European Fertilizer Manufacturers Association (EFMA) Press Release (2008). 5. CO2 Retrofit from Existing Plants, US DOENETL Report 401/110907 (2007).


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