MEA Alternatives Compared: MDEA, AMP, K2CO3 and Ammonia by Cost per Tonne CO2

An aqueous 28–30 wt% monoethanolamine (MEA) solution remains the reference absorber in post-combustion CO2 capture. Typical operation uses a counter-current packed column with structured packing, absorber temperature 40–50°C, stripper bottom temperature 120–125°C, and regeneration reboiler duty 3.6–4.0 GJ/tCO2 for pulverised coal flue gas. The cost per tonne CO2 avoided is commonly reported between 45 USD/tCO2 and 95 USD/tCO2; the lower figure applies to large lignite-fired units with low steam cost and high CO2 partial pressure, while the upper figure applies to natural gas combined-cycle exhaust where CO2 partial pressure falls below 4 kPa. MEA captures CO2 by fast carbamate formation, limiting rich loading to approximately 0.45–0.50 mol CO2/mol amine and lean loading to 0.10–0.20 mol CO2/mol amine in inhibited service. The steam contribution alone, at 10–20 USD/GJ, accounts for 36–80 USD/tCO2 before CO2 compression, drying, and cooling water are included.

In absorber hydraulics terms, the lean/rich cross-flow plate-and-frame heat exchanger is specified with an approach temperature of 5–10°C; fouling from heat-stable salts can raise this to 15°C and add 0.2–0.5 GJ/tCO2 to reboiler duty. Solvent make-up rates for flue gas MEA service are typically 1.0–3.0 kg/tCO2, depending on oxygen, NO2, and metal ion carryover. Iron concentrations above 10 mg/L in lean solvent indicate active corrosion. Heat-stable salts formed by reaction with SO2 and HCl raise surface tension and foaming in packed sections. Flue gas pre-treatment, solvent filtration, and degradation-control systems therefore contribute directly to the cost per tonne CO2 of the reference MEA loop, and the same boundary must be applied when comparing MDEA, AMP, K2CO3 and ammonia alternatives.

Does MDEA Deliver Lower Cost per Tonne CO2 Outside Natural Gas Pressure Ranges?

Methyldiethanolamine (MDEA), a tertiary amine with a pKa of 8.5–8.6, cannot form carbamates directly; CO2 absorption proceeds through bicarbonate formation with a lower reaction enthalpy of approximately 50–60 kJ/mol CO2, compared with 80–85 kJ/mol CO2 for MEA. This reduces reboiler duty in high-pressure gas-treating applications to 2.0–3.0 GJ/tCO2, depending on lean loading and flash configuration. However, the second-order rate constant for CO2 absorption into MDEA is roughly 5–20 m³/kmol·s at 25°C, which is one to three orders of magnitude lower than that of MEA. In atmospheric flue gas with CO2 partial pressures of 3–15 kPa, the resulting absorber height and circulation rate become prohibitive unless a promoter such as piperazine is added. Cost per tonne CO2 for promoted MDEA in post-combustion service has been reported in the 55–80 USD/tCO2 range, but full-scale published data is limited and most evidence derives from high-pressure natural gas processing. Operational advantages include thermal stability above 200°C, low corrosivity, and resistance to heat-stable salt formation with H2S; the principal penalty is slow absorption rate at low CO2 partial pressure.

Sterically hindered primary amine 2-amino-2-methyl-1-propanol (AMP) allows bicarbonate formation while retaining a stoichiometric capacity of 1 mol CO2/mol amine, compared with the 0.5 mol CO2/mol amine carbamate limit of MEA. Pilot-scale packed-column data place AMP regeneration duty between 2.8 GJ/tCO2 and 3.5 GJ/tCO2, but precipitation of bicarbonate at temperatures below 20°C and at high lean loadings requires solvent management or blending with piperazine. The cost per tonne CO2 for AMP-based capture is typically bracketed between 50 USD/tCO2 and 75 USD/tCO2, though published data for extended multi-cycle coal flue gas operation is limited; most comparisons derive from process simulation rather than continuous pilot campaigns. Oxidative degradation of AMP can produce ammonia and acetone-derived products, and aldehyde accumulation in the lean stream increases foaming tendency. Blended AMP-MEA systems raise absorption rate but shift regeneration energy and degradation profiles nonlinearly, requiring liquid-phase FTIR or ion chromatography monitoring before sustained use.

Hot Potassium Carbonate Operating Windows and Vanadate Inhibition

Potassium carbonate (K2CO3) systems operate at 20–35 wt% concentration with absorption temperatures of 90–120°C, avoiding the quench-cooling step required by amine solvents. The solvent cost is lower than MEA, and the reaction energy for bicarbonate formation is approximately 40–55 kJ/mol CO2. However, unpromoted K2CO3 exhibits mass-transfer-limited CO2 flux at atmospheric pressure and is generally unsuitable for post-combustion CO2 partial pressures below 10 kPa. Piperazine-promoted K2CO3 raises absorption rates by a factor of 5–10, enabling shorter absorber heights while preserving regeneration energy around 2.5–3.5 GJ/tCO2. Cost per tonne CO2 estimates for hot carbonate capture in coal flue gas fall between 50 USD/tCO2 and 85 USD/tCO2, but bicarbonate precipitation below 70°C and regenerator corrosion require continuous management. Vanadium-based corrosion inhibitors are common in high-pressure gas service, but their performance in flue gas service can be compromised by oxygen and fly ash. Published data for full-scale K2CO3 post-combustion capture is limited, with most evidence derived from wetted-wall columns and small pilot units.

When Chilled Ammonia Slip Exceeds 5 ppmv, Acid-Wash and Aerosol Control Become Cost Drivers

Chilled ammonia process (CAP) uses aqueous ammonia at 0–10°C to absorb CO2 as ammonium bicarbonate and ammonium carbonate, with regeneration at elevated pressure and moderate temperature. The process lowers reboiler duty to 2.0–2.5 GJ/tCO2, and cost per tonne CO2 on pulverised coal flue gas has been reported in the 35–60 USD/tCO2 range. The total cost is strongly dependent on ammonia slip abatement, including acid-wash absorbers, mist eliminators, and continuous NH3 measurement down to 1 ppmv. Uncontrolled ammonia losses can reach 5–10 kg NH3/tCO2 captured; at ammonia prices of 400–600 USD/t, this adds 2–6 USD/tCO2. The main technical risk is not CO2 absorption rate but solid ammonium bicarbonate formation in cold sections and heat exchanger fouling. Chilled ammonia also requires high-purity ammonia makeup and a pre-treatment train to avoid sulfate and nitrate accumulation. Published data for commercial-scale CAP is limited to a few demonstration units, so comparisons with MEA contain uncertainty from scale-up and aerosol measurement protocols.

Normalising Solvent Degradation, Corrosion and Emission Boundaries for Cost Assessments

Cost-per-tonne comparisons are meaningful only when system boundaries, energy penalties, and solvent degradation losses are normalised. ISO 14064-1:2018 requires quantification of direct and indirect emissions from capture systems but does not prescribe solvent selection. ASTM G31-72 provides a method for immersion corrosion testing of metals in laboratory solvent environments, while ASTM D664-18e2 defines acid number measurements useful for tracking amine degradation acids. No single ISO or ASTM standard directly certifies a solvent’s cost per tonne CO2, so comparative figures must be based on consistent thermal input, compression duty, and make-up rates. Table 1 summarises comparative data using a consistent basis of captured CO2 at the post-compression battery limit.

The comparative cost figures above require the boundary assumptions listed in Table 2. These values derive from typical post-combustion coal flue gas service with high plant availability and do not apply directly to high-pressure natural gas or syngas CO2 removal.

In high-pressure natural gas and syngas service, MDEA and hot K2CO3 have decades of operational history, but their cost per tonne CO2 advantage narrows when applied to dilute flue gas without promoters. AMP offers a stoichiometric capacity advantage over MEA, but its industrial cost basis remains less documented than MEA. Chilled ammonia shows the lowest reported energy requirement among the alternatives, yet the published cost range widens when NH3 slip is treated as a compliance and solvent-loss cost rather than a negligible side stream. Direct comparison of these capture systems requires the same in-plant battery limit, the same flue gas CO2 concentration, and the same compression pressure at the CO2 product boundary.