Industrial design and optimisation of CO2 capture, dehydration and compression facilities
On an industrial-scale process, a comprehensive engineering design and optimisation study was conducted for CO2 capture, dehydration and compression facilities based on flue gases from natural gas and coal- fired power plants.
Ahmed Aboudheir, HTC Purenergy
Gavin McIntyre, Bryan Research & Engineering, Inc
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The HTC designer solvent was utilised in this chemical absorption process to achieve CO2 recovery targets from 80 to 90%. The captured and conditioned CO2, with more than 99 mol% purity, was compressed to 150 barg and sent out at the boundary limit for enhanced oil recovery applications. The main design and engineering factors affecting the CO2 capture, dehydration and compression processes have been highlighted in this paper. The study provides a feasible engineering design and acceptable production cost, taking into consideration all the technical, economic and plant location factors. The study shows that it is advantageous to use the HTC designer solvent over the conventional monoethanolamine (MEA) solvent mainly due to its lower steam consumption, solvent losses, circulation rate,and cooling water requirements. Based on the objective function, the assumed industrial constraints and the plant location factor, the production cost is estimated to be about 49 US$/ton CO2 for the 90% CO2 recovery of 4.0 mol% CO2 content in the flue gas of a natural gas combined cycle power plant. However, a substantial reduction in the production cost was reported for higher CO2 contents in the flue gas of a coal power plant. For a similar CO2 production capacity of 3307 ton per day from a 12 mol% CO2 content in flue gas of a coal-fired power plant, the production cost is about US$ 30/ton CO2. This substantial reduction in the production cost is mainly because of the higher CO2 contents in the flue gas.
The removal of carbon dioxide, CO2, from gaseous mixtures by means of liquid absorbents will continue to be one of the leading industrial applications in the field of gas absorption for many decades to come from both industrial and environmental points of view. The removal of CO2 by liquid absorbents is widely implemented in the field of gas processing, chemical production and coal gasification. Today, many power plants also start considering the post-combustion option to meet the environmental regulation and to produce CO2 for enhanced oil recovery applications. Some major industrial processes that require CO2 removal to achieve specific cleanup targets are presented in Table 1. As can be seen from this table, the cleanup target, which is the allowable extent of CO2 in the treated gas to meet product specifications or environmental regulations, varies from process to process. For example, the cleanup target for CO2 is 1% by volume for pipeline gas. However, for ammonia and LNG manufacture, CO2 must be reduced to 16 ppm and 50 ppm, respectively. For power plant flue gases, it is acceptable to set the cleanup target to less than 0.5% for NGCC power plants and less than 1.5% for coal power plants, from an environmental and economical points of view.
From an environmental point of view, Figure 1 illustrates actual data of fuel consumption in 2005 and an estimation of energy demand of different fuel types for years to come, from 2010 to 2030. It can be seen that the world energy demand will gradually increase at rates of 10-15% every 10 years. This increase will raise the CO2 emissions without doubt to about 50% by 2030 in comparison with the current level of CO2 emissions. The industrial countries (North America, Western Europe and OECD Pacific) contribute in this jump in emissions by 70% compared to the rest of world and about more than 60% of these emissions will come from power generation and industrial sectors.1
Greenhouse gas emissions, including CO2, should be limited, as recommended at the Kyoto Conference, Japan, in December 1997, and Bali Conference, Indonesia, in December 2007.2 Despite the strong recommendations and plans in these conferences, there are hardly any investments in the CO2 capture facilities by the industrial sectors toward meeting these cleanup targets, mainly because of the high production cost of CO2 from flue gases. One of the methods to reduce the CO2 capture cost is to design an energy-efficient gas absorption process. Based on the findings of a recent conceptual engineering study, HTC Purenergy estimated the production cost to be US$ 49/ton CO2 (US$ 54/tonne CO2) for the 90% CO2 recovery of 4 mol% CO2 content in the flue gas of NGCC, as documented elsewhere.3 In this work, a substantial reduction in the production cost was reported for higher CO2 contents in the flue gas of a coal power plant.
Scope of work and constraints
The overall scope of work for this study is to provide an energy-efficient CO2 capture plant design from a coal power plant to produce 3307 ton per day. The plant shall include flue gas pre- conditioning and post-capture conditioning including compression.
The design of the facility is based on the specified flue gas conditions, CO2 product specifications, and constrains. The flue gas conditions utilised in the design is presented in Table 2. The bulk removal of CO2 is recommended to capture 90% of the CO2 from the flue gas of this coal-fired power plant.
The main CO2 product specifications are specified as follows:
• Recommended design level of oxygen content in the product stream is 50 ppm
• Target for water content is <10 ppm and -50°F dew point. This specification is required after the compression facilities and before the pipeline transfers the product to the client
• Maximum nitrogen content in the CO2 product is 2%
• Minimum CO2 product pressure at the compressor inlet is 3 psig.
The technology utilised by HTC Purenergy is based on the bulk removal of CO2 by liquid chemical absorbents from flue gas streams. This is a suitable process technique for treating high- volume gas streams containing CO2 at low pressure produced from utility power plants. The formulated solvent recommended for the CO2 absorption process is a mixed amine solvent consisting mainly of primary, secondary and tertiary amines, which are available commercially. The mixture concentration and the amine ratios are proprietary information.
Inputs and constraints:
The main design and operation constraints of the plant can be presented as follows:
• Flow rate of the flue gas (slipstream) to design the plant is 456 lb/s (207 kg/s) at 180°F and 14.145 psia. This flow rate is calculated to produce 3307 ton per day (3000 metric tonne per day) of CO2 at a 90% CO2 recovery
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