CO2 Capture Solvent Selection Guide

Rev 1 — 2026-04-16 | Domains: Green Energy / eFuels, Process / Chemical

Overview

Amine-based absorption is the most commercially proven technology for post-combustion CO2 capture, and solvent selection is the single most impactful decision in plant design. The solvent determines your reboiler duty (the dominant OPEX), equipment sizing, corrosion management, and environmental footprint. This guide covers the major solvent families, when to use each, and the trade-offs that matter in practice.

Key metric: Specific reboiler duty (SRD), measured in GJ/tonne CO2 captured. MEA baseline is ~3.6-4.0 GJ/t. Advanced solvents target <2.5 GJ/t. Every 0.5 GJ/t reduction is roughly $5-8/tonne CO2 in operating cost savings.

Solvent Comparison Matrix

Solvent	Type	Typical Conc. (wt%)	SRD (GJ/t CO2)	CO2 Loading (mol/mol)	Degradation Rate	Corrosion Risk	Commercial Status
MEA (monoethanolamine)	Primary amine	30	3.6-4.0	0.40-0.50	High (O2, SO2, NOx)	High (use CS + SS cladding)	Fully commercial — 50+ years in gas treating
MDEA (methyldiethanolamine)	Tertiary amine	40-50	2.5-3.0	0.50-0.70 (with activator)	Low	Low	Fully commercial — standard for natural gas sweetening
MDEA + Piperazine	Activated tertiary	40+5 to 40+10	2.5-2.8	0.55-0.65	Low-moderate	Low-moderate	Commercial — widely deployed in gas processing
KS-1 / KS-21 (MHI)	Proprietary hindered amine	Proprietary	2.8-3.2	~0.50	Low	Low-moderate	Commercial — 15+ plants including Petra Nova (240 MW)
CESAR1 (AMP + PZ)	Blended hindered + cyclic	27+13	2.7-3.1	0.55-0.65	Moderate	Moderate	Pilot/demo — Technology Centre Mongstad, ALIGN-CCUS
Concentrated Piperazine (PZ)	Cyclic diamine	40	2.1-2.5	0.70-0.85	Very low	Low	Pilot — UT Austin SRP. Solid precipitation below 15°C requires management
Cansolv DC-103 (Shell)	Proprietary secondary amine	Proprietary	2.5-2.9	~0.55	Low	Low	Commercial — Boundary Dam Unit 3 (110 MW, 1 Mtpa)
Hot Potassium Carbonate (Benfield)	Inorganic	25-30% K2CO3	2.0-2.5	0.35-0.45	None (inorganic)	Moderate (high-pH erosion)	Commercial — 700+ units worldwide for high-pressure CO2

Decision Framework: Which Solvent When?

Post-Combustion Capture (Flue Gas: 4-15% CO2, ~1 atm, O2 present)

This is the hardest application — low CO2 partial pressure means you need a fast-reacting solvent with high absorption capacity at low loading.

Default choice: 30 wt% MEA — well-understood, ample design data, but highest energy penalty and degradation
Better choice if available: Proprietary solvents (KS-1, Cansolv DC-103, CESAR1) offer 15-30% energy reduction over MEA
Emerging best-in-class: Concentrated piperazine — lowest demonstrated SRD (~2.2 GJ/t) but requires precipitation management and is still in pilot/demo stage
Avoid: MDEA alone (too slow without activator for dilute CO2), hot potassium carbonate (too low partial pressure for effective absorption at atmospheric pressure)

Pre-Combustion / Syngas Treating (15-40% CO2, 20-70 bar)

High pressure and high CO2 concentration. Physical solvents become competitive here.

Activated MDEA (aMDEA): The workhorse — BASF's aMDEA process has 200+ references
Selexol (DMPEG): Physical solvent for very high-pressure applications. No heat of reaction — regeneration by pressure letdown (flash). Best above 30 bar
Rectisol (cold methanol): For ultra-pure CO2 (<1 ppm) required for chemical synthesis. Used in all major coal-to-liquids and methanol plants

Natural Gas Sweetening (CO2 + H2S, 30-100 bar)

MDEA: Selective for H2S over CO2 — the standard choice when you want to remove H2S while slipping CO2
MDEA + Piperazine: When you need both H2S and CO2 removal
Sulfinol (MDEA + sulfolane): Mixed chemical-physical for high acid gas loads and heavy mercaptans

Key Design Parameters by Solvent

Parameter	MEA 30%	MDEA+PZ	Conc. PZ 40%	Hot K2CO3
Rich loading (mol CO2/mol amine)	0.45-0.50	0.55-0.65	0.75-0.85	0.40 (equiv)
Lean loading (mol CO2/mol amine)	0.20-0.25	0.05-0.15	0.25-0.30	0.25 (equiv)
Reboiler temperature (°F)	240-260	240-260	300-310	230-250
Reboiler pressure (psig)	20-25	20-30	55-75	15-25
Absorber packing: structured (Y/N)	Yes	Yes	Yes	Random or structured
Typical L/G ratio (gal/SCF × 1000)	3.0-5.0	2.5-4.0	1.5-2.5	8.0-15.0
Makeup rate (lb/tonne CO2)	1.5-3.0	0.5-1.5	0.2-0.5	0.1-0.3
Solvent cost ($/gal, 2025)	$4-6	$8-15	$20-30	$1-2

Degradation and Emissions — The Hidden Cost

MEA degrades via three pathways, and the degradation products are environmentally significant:

Oxidative degradation (O2 in flue gas): produces ammonia, formate, acetate, glycolate, oxalate, and heat-stable salts (HSS). This is the dominant pathway in post-combustion capture. Mitigation: oxygen scavengers (not always effective), inhibitors (Inhibitor A), or switch to more resistant solvents
Thermal degradation (reboiler >140°C): produces HEIA, oxazolidone, and higher-molecular-weight polymers. Mitigation: limit stripper bottom temperature to 120°C for MEA; PZ can tolerate 150°C+
SO2/NOx degradation: produces sulfamate, nitrosamine (NDELA, NMOR). Nitrosamines are carcinogenic — this is a major permitting concern in the EU (Norway's TCM extensively studied this). Mitigation: wash water section on absorber stack, pre-scrubbing to remove SO2 below 10 ppm

Nitrosamine warning: Secondary amines (DEA, morpholine, piperazine) form stable nitrosamines. Primary amines (MEA) form unstable nitrosamines that decompose rapidly. This is a real permitting issue in Europe — ensure your Environmental Impact Assessment addresses nitrosamine emissions if using secondary/tertiary amines.

References

Rochelle, G.T. — "Amine Scrubbing for CO2 Capture," Science, 325(5948), 2009
IEAGHG Report 2019/09 — "Further Assessment of Emerging CO2 Capture Technologies for the Power Sector"
Frailie, P.T. & Rochelle, G.T. — "Modeling of CO2 Capture by Concentrated Piperazine," Int. J. GHG Control, 2014
CESAR Project Final Report — "CO2 Enhanced Separation and Recovery," EU FP7, 2011
Boundary Dam CCS Project — SaskPower Performance Reports (2014-2024)
Kohl, A.L. & Nielsen, R.B. — Gas Purification, 5th Ed. (Gulf Publishing), Ch. 2-4
Campbell, J.M. — Gas Conditioning and Processing, Vol. 2, Ch. 21 "Acid Gas Treating"