Technology status and R&D needs

MEA based absorption systems were developed over 60 years ago to provide a general non-selective solvent process to remove acid gas

impurities, e.g. H2S and CO2, from natural gas streams. The process was then adapted to treat flue gas streams for CO2 capture for subsequent use in the carbonation of brine, dry ice formation, urea production and the

carbonation of drinks. It has also been used for production of CO2 for enhanced oil recovery (EOR) operations (Chapter 4). Table 2-1 gives a summary of a selection of CO2 plants that are in commercial operation.

These plants are typically much smaller than an electric utility scale, however, according to the manufacturers it is considered to be technically feasible to build an absorption plant to separate CO2 from a power plant flue gas stream.

Commercial CO2-absorption plants are available to a size at least fitting a 400 MWe coal fired power plant from 2-3 potential suppliers world wide.

Operator Location Capacity (tonnes/day CO2)

Fuel Sources CO2 Use Technology Status

IMC Global Trona, CA 800 Coal boiler Carbonation of brine (soda ash)

Kerr-McGee MEA Operational since 1978 Mitchell Energy Bridgeport, TX 493 Gas heaters,

engines, turbine

EOR Inhibited MEA Operational since 1991 Northeast Energy

Associates Bellingham, MA 320 Gas turbines PURPA

(food-grade) Fluor Daniel Operational since 1991 Applied Energy

Systems Poteau, OK 200 Coal boiler

(fluidized bed) PURPA

(food grade) Kerr-McGee MEA Operational since 1991

Food-grade Fluor Daniel Operational since 1994 Luzhou

Natural Gas China 160 NH3 plant

reformer exhaust

Urea Fluor Daniel Operational since 1998 Indo Gulf

Fertilizer Co. India 150 NH3 plant reformer exhaust

Urea Dow MEA Operational

since 1988 Prosint Rio de Janeiro,

Brasil 90 Gas boiler Food-grade Fluor Daniel Operational since 1997 Liquid air

Australia Australia 2 x 60 Gas boiler Food-grade Dow MEA Operational since 1985 AES, Shady Point

Power Station Panama, OK 190 Coal fired CFB

boiler Food-grade ABB Lummus Operational since 1991 AES, Warrior Run

Power Station Cumberland, MA 150 Coal fired CFB

boiler Food-grade ABB Lummus Operational since 1999

Table 2-1 Commercial CO2 plants (main source: IEA GHG data base, see www.co2sequestration.info)

The US-based power company AES operates two CO2 absorption plants located at coal-fired units at Shady Point Power Station, Oklahoma and Warrior Run Power Station, Maryland. Both absorption plants are designed and constructed by the same supplier. The CO2 absorption plant at Warrior Run was commissioned in year 2000 and the plant at Shady Point was commissioned in year 1991. The CO2-absorption plants have nearly the same capacity.

The Shady Point plant is located at a coal fired CFB with two boiler units.

Local coal is fired (HHV 26.2 MJ/kg, ash 18 % and sulphur 2.7 %) and the power output is 320 MWe. The CO2 plant is located adjacent to the power plant and captures CO2 from a flue gas slipstream using MEA scrubbing technology. For CO2 capture the SO2 concentration is reduced from 500 ppm to 2 ppm by scrubbing with caustic soda. The capacity of the plant is 200 tonnes CO2/day for food grade use.

Elsam representatives visited Shady Point plant in May 2003 and report that the plant has been in operation without problems. There has only been very minor corrosion even though the main material is mild steel. In the absorber, only the top is made of stainless steel. The original absorber packings are present after 12 years of operation and the plant is equipped with anti-foaming plant which has never been used.

Power plant integration

One of the advantages of using the post combustion capture approach with amine absorption is that it can be added on to a conventional power plant

without incurring any major modifications. It can therefore be used for retrofitting existing plants to include CO2 capture capabilities. The main change is to the steam cycle where the major part of the steam exiting the IP turbine is extracted and expanded to the reboiler pressure to supply the heat for regeneration of the solvent. The power output is thereby reduced by up to 20 %. Due to the drastically reduced mass flow in the LP section of the steam turbine, some modifications on the turbine may be required. Figure 2.3 shows a scheme of a power plant with SO2 and CO2 flue gas scrubber and steam extraction for solvent regeneration.

Figure 2-3 Scheme of a power plant with SO2 and CO2 flue gas scrubber and steam extraction for solvent regeneration R&D needs

Below follows a summary of the research and development needs that have been identified for amine-based CO2 absorption.

R&D related to absorbents

• Reduce steam consumption and temperature requirement for regeneration

o More energy efficient amines required (lower energy

requirement for regeneration, lower regeneration temperature, higher concentration)

o Optimise blend of amines

• Reduce power consumption

o Develop amines with a higher CO2 loading that could be

applied at a higher concentration to reduce pump requirements and equipment size

o Optimise blend of amines

• Decrease loss of amine into the flue gas or CO2

o Amines with a lower vapour pressure are desirable

• Reduce degradation of amines

o Develop amines less sensitive to high temperature, SOx, NOx, O2

o Develop inhibitors, process modifications, membranes

• Develop other types of absorbents

Existing plant

SO2 absorber CO2 absorber

CO2 compressor

stripper

Other areas for development

• Integration possibilities with power plant should be investigated o Integration between reboiler and reclaimer and IP steam

extraction

o Use of heat from CO2 compression intercooling for feedwater preheating

o Find integration possibilities for use of heat from flue gas cooler, lean amine solution cooler, reflux condenser and CO2

dryer (e.g. district heating, feed water preheating etc.)

• Reduced flue gas blower requirement

o More efficient packing to reduce absorber pressure drop

• Process optimisation for large scale plant

o Process modifications, e.g. split flow solvent process (lean and semi-lean solution)

o Improve simulation tools used for optimisation to better predict performance

o Investigate possibilities for cost reductions due to economy of scale

• Demonstration of long-term operational availability and reliability on a full-scale power plant using relevant fuels.

2.4 Pre-combustion carbon capture