The first pilot project that uses chilled ammonia to capture carbon dioxide (CO2) from coal fired power plants is now operational. Sean Black of Alstom explains how the chilled ammonia process works.

Sean Black, Alstom, France

Alstom has developed a chilled ammonia process (CAP) to capture carbon dioxide (CO2) and isolate it in a highly concentrated, high-pressure form. In laboratory testing, it has demonstrated the potential to capture more than 90 per cent of CO2 at a cost that is far less than other carbon capture technologies. Once captured, the CO2 can be used commercially or sequestered in suitable underground geologic sites.

The French company is now engaged in an extensive development and commercialization programme, with the objective of offering a fully commercial product to the marketplace by 2015. The process has the potential to be applied to capture CO2 from flue gases exhausted from coal fired boilers and natural gas combined-cycle (NGCC) systems, as well as a wide variety of industrial applications.

The concept described below is currently being tested in a field pilot plant that has been constructed at the We Energies’ Pleasant Prairie power plant (P4) in Wisconsin, USA. Alstom has designed, constructed and is operating a 1.7 MW system that captures CO2 from a portion of coal fired boiler flue gas at the plant, which is a 1210 MW generating station. The demonstration project will provide the opportunity to test the process on a larger scale and to evaluate its potential to remove CO2 while reducing the energy used in the process.

In 2006, Alstom, the Electric Power Research Institute (EPRI) and We Energies announced the development of the field pilot to be installed and operated at P4. As the technology developer, Alstom is responsible for the design, construction, operation and maintenance of the carbon capture facility. This pilot was designed to capture CO2 from a slipstream of less than one per cent from one of the two boilers operating at P4.

The main objectives of this project are the following: (1) Demonstrate full system operation on actual flue gas, including but not limited to: flue gas cooling using heat recovery/exchange and chilling, removal of residual pollutants, CO2 absorption and regeneration; (2) Evaluate energy consumption relative to calculated values and to other CO2 capture technologies; (3) Identify O&M issues and begin to establish system reliability; (4) Conduct field tests to gather operating data from the system and develop objective, third-party techno-economic analyzes to refine current estimates for the performance and lifetime costs of a commercial system.

The construction of the carbon capture facility commenced in July 2007, and pilot testing commenced in March 2008. The project will remain operational for at least one year. During this time, EPRI will conduct an extensive test programme to collect data and evaluate technology performance. Alstom expects that initial results from the pilot plant will be published in late 2008.

At maximum capacity, the pilot plant is designed to capture over 1600 kg CO2/h (almost 15 000 tonnes/year). Several other field pilot and demonstration projects (discussed below) are currently in various stages of development. Optimization and improvements based on these pilot and demonstration projects will impact the final design of the commercialized process. This article captures the main features and advantages of the process.

The process is designed to take advantage of the very attractive characteristics of using ammonium carbonate solution, while minimizing ammonia losses to the atmosphere. The feasibility of the key features described herein have been confirmed in small and large bench scale tests performed over the past three years.

A schematic of the integrated process is shown in Figure 1. The system is expected to achieve high removal of CO2, as well as reduction of residual emissions of SO2, HCl, SO3, and particulate matter.


Figure 1: Process flow diagram of the chilled ammonia process retrofitted downstream of a flue gas desulfurization (FGD) system
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Flue gas cooling

The flue gas exiting the FGD is typically between 120-140 °F (50-60 °C). The gas is water saturated and it contains residual contaminants such as SO2, NOx, HCl, sulphuric acid mist and filterable and condensable particulate matter. In order to cool the saturated flue gas, both sensible heat and latent heat for water vapour condensation has to be removed.


Figure 2: Illustration of the chilled ammonia field pilot at We Energies’ Pleasant Prairie power plant
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Direct cooling with no heat exchangers using cooling towers and mechanical chillers is an efficient and low cost method that results in condensation of water and the capture of residual emissions from the flue gas. The pH of the water in the flue gas cooling subsystem will be controlled using an alkaline reagent.

The net water balance around the flue gas coolers, with moisture condensing in the direct coolers and evaporating in the cooling towers is close to being even. The impact of the cooling-condensing operation on the volume of the flue gas is given in Figure 3. As it illustrates, the volume of the saturated flue gas is over 30 per cent smaller at 32 °F compared to the volume at 140 °F.


Figure 3: The impact of the cooling-condensing operation on the volume of the flue gas
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The reduction in volume and mass of the flue gas has the benefit of reducing the size of the downstream equipment. The ID fan will be installed downstream of the cooling subsystem, minimizing its size and power consumption. The flue gas entering the CO2 absorber is cooled, it is relatively dry with less than one per cent moisture, and it contains very low concentrations of SOx, HCl and PM.

The CO2 absorber is designed to operate with a solution containing a dissolved and suspended mix of ammonium carbonate and ammonium bicarbonate. The flue gas flows upwards in counter current flow. Up to 90 per cent of the CO2 from the flue gas can be captured in the absorber.

The low concentration of ammonia in the clean flue gas will be captured by a cold-water wash and returned to the absorber. The clean flue gas, containing mainly nitrogen, excess oxygen and residual CO2 flows to the chimney for venting to the atmosphere. The CO2 rich solution from the absorber primarily contains ammonium bicarbonate. The CO2 rich solution is pumped to a high pressure through a heat exchanger, and to the high-pressure regenerator. The pressure required for the CO2 gas at the plant boundary limits is typically 100 bar. This represents a compression ratio of around 100, relative to ambient conditions.

In contrast, the proposed process regenerates CO2 at 20 bar. This reduces the required compression ratio from 100 to 5. The result is a compression train that has fewer stages and consumes less power.

The ammonium bicarbonate in the CO2 rich slurry dissolves as the temperature increases in the heat exchanger and turns into a clear solution at temperatures above 175 °F. The hot solution is injected into the regenerator, which is a high-pressure vessel.

Addition low pressure steam. Bench scale testing has demonstrated that the CO2 gas from the regenerator and resulting wash system is extremely pure, containing more than 99 per cent CO2 and extremely low residual concentrations of ammonia and water.

Features of a commercial system

Studies have been developed to evaluate the potential energy consumption and the cost of a full-scale CO2 capture system. An initial study was developed to compare the CAP to a conventional MEA system, evaluated in a study developed by Parsons for EPRI and US DOE in 2000 and 2002.

The base power plant is a supercritical PC boiler firing 333 542 lb/h (159 292 kg/h) Illinois #6 coal operating at 40.5 per cent net efficiency (HHV) and generating 462 MW of net power. The results of this study demonstrated the potential of the CAP to provide significant energy savings, relative to conventional MEA systems.

As compared with a conventional MEA system, the biggest energy savings results from the reduced consumption of low pressure steam for absorbent regeneration. This is due to: (1) the lower heat of reaction; (2) the very small amount of water vapour leaving the regenerator with the CO2 stream; and (3) lower sensible heat loss due to higher CO2 net loading in the solvent and hence lower circulation rate.

The steam consumption can be further offset through the use of low-grade reject heat from the boiler island. The main auxiliary power saving relative to a conventional MEA system is the smaller CO2 compressor that results because the CAP regenerates CO2 under pressure. This eliminates the need for the largest and least efficient compression stage. Additional power is required for flue gas cooling, with the actual power consumption dependent upon ambient conditions.

Alstom has since commenced internal studies to evaluate a commercial scale-up of the CAP. These initial studies currently estimate the average energy penalty at around 20-25 per cent of net boiler output. However, Alstom’s goal is to achieve an average energy penalty of below 20 per cent for a typical site. Under ideal site conditions, initial studies suggest the process can potentially be designed to operate with an energy penalty that is well below 20 per cent.

Ammonia advantages

Other advantages over conventional MEA and advanced amine based technologies include the ability to offset low-pressure steam consumption through the use of low grade reject heat and the ability to utilize local access to cold water to further offset mechanical chilling and further reduce auxiliary power consumption.

The fact that ammonium carbonate is a stable reagent over a wide range of temperatures means that it does not degrade during absorption nor regeneration and does not react with oxygen. Ammonia used as process make-up is a commodity chemical that can be added to the process in various forms, including: anhydrous ammonia, aqueous ammonia or ammonium bicarbonate.

The process by-products are limited to a single, liquid waste stream that can be reutilized or disposed of within the existing power plant infrastructure, potentially reutilized outside the power plant, or cost-effectively treated for non-hazardous disposal.

Another advantage is that the process can be retrofitted to existing power plants that have modern-design air quality control systems, without the need to install additional, polishing devices for fine control of traditional air pollutants; no additional control of conventional emissions is required. Finally, the process will further reduce emissions of conventional pollutants; the actual performance to be validated in upcoming field pilot testing.

Development and commercialization

Alstom is engaged in an extensive development program to fully commercialize the CAP for postcombustion capture of CO2 emissions from power plants by 2015. Subsequent releases of the proposed technology will target CO2 capture from other applications in both power generation and industry.

Over the past 36 months, bench scale testing performed at SRI International has been funded by Alstom, EPRI, and other third-parties and has achieved the following objectives: (1) Demonstrated ability to capture 90 per cent CO2 with low ammonia emission; (2) Initial screening of different designs to optimize the design of the CO2 absorber system; (3) Improved the understanding of the fundamental system parameters; and (4) Identified and evaluated key components for future phases of development.

The large bench scale pilot commenced operation in October 2006 and continues to provide valuable insight about the process.

More projects in the pipeline

In addition, Alstom has since announced the development of a similar pilot project to be constructed at the E.ON gas fired Karlshamn power plant that is located in Karlshamn, Sweden. This pilot is identical in size to the P4 field pilot but sincorporate some recent innovations. This project is currently in final engineering and on schedule to commence testing later this year.

In March 2007, Alstom announced a collaboration with American Electric Power (AEP) to develop and construct a validation project at AEP’s Mountaineer Power Plant in West Virginia, USA. Preliminary engineering commenced in 2007 and the project is scheduled to commence operations in 2009. When the unit commences operation it will capture more than 100 000 tonnes of CO2 per year.

The captured CO2 will be compressed and pumped into two wells that are located on the plant property. Successful operation over several years will demonstrate the viability of CO2 capture and storage on a large scale.

These results will be incorporated in the design and construction of a commercial-scale demonstration project that treats approximately half of the flue gas from one of AEP’s existing generating stations. This unit is scheduled to commence operation sometime after 2012 and will be designed to capture an estimated 1.5 million tonnes per year of CO2. The CO2 from the commercial-scale demonstration project may be piped to oilfields for enhanced oil recovery (EOR) or used to further develop the understanding of geologic storage.

Alstom announced in July last year an agreement to collaborate with the European Test Centre Mongstad (TCM) to develop a large-scale demonstration facility to capture 100 000 tonnes per year of CO2 from a combined heat and power plant and a catalytic cracker operating at StatoilHydro’s Mongstad Refinery in Norway. TCM partners include Gassnova SF and a number of other prestigious partners.

The successful completion and performance of these various projects will demonstrate to the market a fully validated technology ready for commercial sale for new projects in development, as well as retrofit to existing facilities that require post-combustion capture of CO2 emissions.