Large-scale carbon capture with Econamine FG Plus

Dr Satish Reddy and Dennis W Johnson of US-based Fluor Corporation explain the benefits of the company’s proprietary amine-based technology for post-combustion CO2 capture.

Econamine FG PlusSM (EFG+) is a Fluor proprietary amine-based technology for large-scale post-combustion CO2 capture. The EFG technology is the first and most widely-applied process that has extensive proven operating experience in the removal of carbon dioxide from high oxygen containing flue gases (up to 15 vol%).

Fluor Corp, North America’s largest publicly-traded engineering-construction firm, is also a leading supplier of technology for post-combustion capture of carbon dioxide from flue gases that result from combustion of fossil fuels. Fluor has completed a number of front-end engineering and design (FEED) studies for application of CO2 capture systems from plants fired with coal, natural gas, and oil.

EFG+ is a proven technology, with 25 plants licensed and built worldwide over the past 20 years. These plants have ranged in size from as small as 2tpd of CO2 capture to as high as 320tpd. Furthermore, the technology has been demonstrated on different flue gas sources, including gas turbine exhaust, gas furnace exhaust (eg steam reformer), fuel oil boilers (heavy and light fuel oil), natural gas fired boilers, and gas engine exhaust. A pilot plant level demonstration was run on a coal-based flue gas with successful results.

Even though the EFG+ technology has been commercially proven in these past projects, the technology will be demonstrated for coal-fired boiler flue gas on a semi-commercial scale with a recent solvent formulation and plant configuration enhancements.

Coal-based flue gas EFG+ demonstration

In July 2008, E.On Energie and Fluor formed a strategic partnership to jointly build a CO2 capture project to demonstrate the performance of the EFG+ technology on a coal-derived flue gas. The plant is sited at E.On’s coal-fired power station at Wilhelmshaven near Hamburg, Germany.

While the basic chemistry will be the same as capture from other flue gas sources, CO2 capture from coal-fired flue gas has process deviations from previous applications. In particular, this plant would demonstrate the EFG+ plant’s capability to handle increased flue gas contaminants (SOX, NOx, fly ash, HCl, HF, etc.) and high CO2 concentration. Of particular interest to the power industry are the effectiveness of the solvent to handle the real flue gas conditions, the capability of the plant to capture at least 90% of the incoming CO2, and the energy requirement for the CO2 capture. Also, of concern is the effectiveness of the CO2 capture system to operate in contact with small amounts of acid gases (SO2, SO3, NO2, HCl, and HF) while demonstrating the effectiveness of reclaiming to contribute to minimisation of both solvent losses and waste production.

The purpose of the CO2 capture demo plant is to demonstrate the applicability of the EFG+ technology on flue gases derived from burning coal via long-term operational experience. In addition, the plant will provide performance data to characterise and ultimately improve the process. The data collected from the plant will be used to:
• improve the energy efficiency of the process identify opportunities for heat integration between the power plant and the capture plant
• lower the environmental impact
• improve the solvent maintenance procedures
• optimise equipment design.

The primary goals of the CO2 capture project are to demonstrate:
• the EFG+ technology on coal-fired flue gas at a semi-commercial scale for an extended period of time
• recently developed energy and cost saving features of the EFG+ technology
• the performance of new EFG+ solvent formulations. Fluor has developed variations of the existing EFG+ solvent and a brand new solvent which has been successfully been tested on a pilot plant scale
• new features that improve the environmental signature of the process including emissions to air.

In addition, the project provides the perfect opportunity for the testing of additional EFG+ technology advancements, whether those are new solvents or new devices / configurations. In this way, the goals of the project will grow as long as the demonstration plant continues to operate.

Figure 1 shows the battery limits of a CO2 capture plant. It is applicable to both a full-scale plant and the demonstration plant which is integrated into the Wilhelmshaven Power Station much like commercial EFG+ plants and features all process steps in a commercial EFG+ system with the exception that the CO2 will not be exported or sold. Currently, there is no intention for use of the captured CO2 and it will be vented back to the stack without compression, oxygen removal or dehydration.

The demonstration is designed for 90% removal of the incoming CO2 in the flue gas. However, flexibility in the plant design will allow for process optimisations and understanding of operation at higher and lower CO2 removal and under the conditions typical of operation on a large coal-fired utility plant, for example:
• operation with variation in coal properties and impact of fly ash and acid gases
• operation with variation in flue gas properties seen downstream of the plants pollution control equipment
• start-up and shut-down
• load following
• turndown of the CO2 capture system
• integration into the plants utilities (steam, power, water)

A comprehensive test plan has been prepared and is summarised below. The test plan for the CO2 Capture Demonstration Plant consists of the following types of tests:
• performance tests at normal and off-design conditions
• performance testing of individual equipment items or systems
• testing of various emissions reduction configurations
• testing of different solvents.

During the above tests, sufficient plant data would be collected such that the plant performance could be fully characterised. The commissioning is expected in the late-2011.

Figure 2 shows a simplified flow diagram of the plant.

The process flowsheet is typical of commercial modern EFG+ designs and includes the following EFG+ features:
• improved solvent formulation
• DCC with trim sulphur removal
• absorber intercooling
• lean vapour compression configuration
• advanced solvent reclaiming technology
• advanced scrubbing system

Integration of carbon dioxide capture with coal-fired power plants

One of the FEED studies completed by Fluor was for The Tenaska Trailblazer Energy Center which will generate approximately 860MW net, using supercritical pulverised coal technology. This plant is designed to capture carbon dioxide produced by combustion and deliver it via pipeline to the Permian Basin oil fields for use in enhanced oil recovery (EOR) and ultimately, geological storage. The Trailblazer Energy Center was awarded a grant from the Global Carbon Capture and Storage Institute (GCCSI) to help fund the FEED study for the power plant’s cutting-edge carbon dioxide capture technology which was completed by Fluor. Fluor’s EFG + carbon dioxide capture technology was selected for the facility.

The Trailblazer Project will be designed to minimise water use by employment of dry cooling technology. Other studies include cooling with water and seawater on both a once-through basis and with the use of cooling towers (air, water, and hybrid). The cooling method influences costs and the design temperature of the carbon dioxide capture process. A preliminary conceptual layout of the Trailblazer CO2 capture system is shown on Figure 3.

The results of the Trailblazer study along with several other studies such as those in Table 1 provide insight to the integration of carbon dioxide capture technology for coal fired applications and identifies solutions to unique challenges associated with carbon dioxide capture integration for a modern power plant.

Some of the most significant challenges for coal applications are developing approaches for reducing the requirements for process steam and electrical power. Integration involves many parts of the coal-fired plant and designing for carbon dioxide capture can result in marked improvement by optimisation of power requirements. New plants with carbon dioxide capture will reap the most benefit if the planning considers peak power demand, steam and electric power consumption, plant layout, and other important aspects related to the addition of carbon dioxide capture. The integration is based on 90% capture of carbon dioxide, a complete design applicable to both new and existing power plants, and consideration for CO2 compression and dehydrating so the CO2 is ready for sale, EOR or sequestration.

Application at coal-fired power plants

Even with the deployment of high-efficiency pollutant-removal technologies, there are still residual quantities of SO2, HCl, NO2, H2SO4, ammonia, particulates, and other trace constituents in the flue gas entering the carbon dioxide capture system. The CO2 absorption solvent will remove the majority of the acidic pollutants, some particulate and other constituents. The presence of certain of these impurities in the scrubbed flue gas, even at low concentrations, increases the complexity and the operating cost of the CO2 capture process without regard to the technology employed. This is especially true for pollutants that will build up or concentrate in the CO2 capture solvent since the accumulation will often require additional operations in the carbon dioxide system in order to maintain desired process conditions.

Figure 4 shows a schematic of a modern coal-fired power plant indicating the boiler, emission control technologies, and the carbon dioxide capture plant. The CO2 Capture Unit depicted for the modern coal-fired power plant includes a polishing FGD and Direct Contact Cooler (DCC) or a DCC with a scrubbing capability, a blower and a CO2 absorber.

In Figure 4, selective catalytic reduction (SCR) is used to control NOx. First ammonia is vaporised, mixed with air, and injected upstream of the SCR where NOx, primarily in the form of NO is converted to nitrogen gas. The next step might be sorbent injection for control of SO3 gas. The sorbent can be injected in any of a number of locations, such as just before the air preheater (APH), but almost always upstream of the particulate control device. Activated carbon injection (ACI) is one method of removing mercury from gas streams. This will also occur upstream of the particulate control device which will usually consist of a dry electrostatic precipitator (DESP) or a fabric filter (FF) or in some cases, both. Figure 4 also shows the path to a wet flue gas desulphurisation (FGD) unit.

Integration of carbon dioxide capture technology with plant steam cycle

For new coal-fired power plants, the integration of carbon dioxide capture technology into the plant’s cycle heat balance needs to be evaluated based on site-specific requirements and conditions. There are various alternatives that may be studied to determine the best solution for a particular application based on:

• project economic factors
• planned CO2 capture efficiency
• planned CO2 capture capacity factor (percentage of time operating)
• final CO2 compression pressure
• percentage of flue gas stream cleaned
• site ambient conditions

As part of the development of the power plant design basis for integrating carbon capture, Fluor evaluates several alternatives to determine the optimal steam cycle design, including:

• carbon dioxide capture process steam extraction source and steam turbine design
• process steam line design optimisation
• process condensate return from carbon dioxide capture equipment
• heat integration between the power cycle and the carbon dioxide capture equipment
• low pressure feedwater heater drains pump design
• reducing O2 infiltration
• consideration for use of potential waste streams from the CO2 capture process within the boiler and FGD systems
• water conservation
• supplemental gas-fired cogeneration to support carbon capture equipment power needs

Summary

The CO2 capture demonstration plant will demonstrate many new features of the EFG+ process. Although many of the features have been demonstrated separately, the demonstration plant will use all of them together and provide a basis for implementation on all large-scale capture plants.

Retrofitting a carbon dioxide capture facility to a power plant offers significant challenges to the design and operation of the power generating facility. The consideration for integrating carbon dioxide capture into a new or existing power plant requires careful analysis and decision-making, beyond simply adding capacity for electrical power and steam. These decisions can play an important part in reducing the impact to the plant and improve the economics of power production.

There are multiple steam cycle design alternatives that may be employed to meet the carbon dioxide capture system energy needs. Project specific factors may result in selection of alternative designs that are better suited to the plant under consideration, thus it is recommended to evaluate plant on a case-by-case basis. The impacts to the plant steam cycle performance, capital costs, operating expenses, and operating flexibility can vary greatly depending on the option utilised to meet this energy need.

Plant- or site-specific issues will play important roles in carbon dioxide capture integration decisions. It is best to evaluate and assess “carbon capture ready” during the initial design study. The study will always need to evaluate economics associated with the use and tradeoffs for steam versus electrical power, water, and other resources associated with a carbon dioxide capture ready plant.

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