Design the giant amine absorber that scrubs CO₂ out of power-plant, steel, and cement flue gas. Adjust flue-gas flow, inlet CO₂ vol%, target capture rate, and pick one of four solvents (MEA, KS-1, Piperazine, MDEA+PZ) to see column diameter, packed height, amine circulation, reboiler duty, and USD/t-CO₂ capture cost change in real time.
Parameters
Flue gas flow Q
m³/h
A coal unit gives about 2,000,000 m³/h, an LNG unit about 1,000,000 m³/h
Inlet CO₂ vol%
vol%
Coal 12-15%, LNG 4-5%, cement kiln 20-30%
Target capture rate
%
Commercial plants 90%, IEA 1.5C scenario 95-99%
Amine solvent
Changes kinetics, capacity, and reboiler duty
Gas inlet temperature
°C
Column top pressure
kPa
Packed height H
m
Designed packing height, compared with required height
Results
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Inlet CO₂ (t/h)
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Captured CO₂ (t/h)
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Amine flow (t/h)
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Required H (m)
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Reboiler duty (MWth)
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Cost ($/t-CO₂)
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Process schematic — lean/rich amine loop
Flue gas enters at the bottom, lean amine falls from the top. CO₂ is stripped as bubbles rise; rich amine leaves the bottom for the regenerator. Colour intensity tracks loading.
Inlet molar flow of CO₂ and captured mass flow. Q is flue gas flow [m³/h], $y_{\rm CO_2}$ is inlet vol%, r is capture rate, 22.4 is the molar volume at STP [L/mol].
Amine circulation and reboiler duty. $C_{\rm amine}$ is capacity [mol/kg], $\Delta\alpha$ is loading swing (~0.3), $q_{\rm reg}$ is specific regeneration heat [GJ/t-CO₂].
"CCS" is everywhere in the news. Is it basically just a fancy filter on the smokestack?
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Close, but not quite. A filter only stops solid particles, and CO₂ is a gas, so you have to grab it chemically. You spray a basic amine solution from the top of a tall packed column while the flue gas climbs from the bottom, and the amine reacts with the CO₂ and pulls it into the liquid. For 1,000,000 m³/h of flue gas, that column can be 10 m wide and 50 m tall — chemical-plant size sitting next to your boiler.
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Got it. When I switch the amine from MEA to KS-1 the reboiler duty drops from 4.0 to 2.5 GJ/t-CO₂. What's the chemistry behind that?
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That's the heart of modern CCS. MEA (monoethanolamine) bonds strongly to CO₂, so the reboiler has to boil off a lot of steam to break that bond — 4 GJ per tonne, the heating value of about 100 kg of fuel oil. KS-1 from Kansai Electric and Mitsubishi Heavy is a sterically hindered amine: the bond is intentionally weaker, so you only need 2.5 GJ/t. Capture cost falls from about $72/t to $60/t, which is why commercial CCS in the US (Petra Nova) and Saudi Arabia (Uthmaniyah) chose KS-1.
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$60/t is below today's carbon-price levels in Europe (€80-100). So why isn't CCS everywhere?
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Three hurdles beyond cost. First, the energy penalty: the host coal plant loses 20-30% of its output — a 500 MW unit becomes effectively 350 MW. Second, storage: you need geology that can take pressurised CO₂ at least 1 km down, which limits sites. Third, amine degradation — oxygen and trace SO₂ break the amine down, so you keep buying make-up solvent. Piperazine reacts four times faster than MEA and shortens the column, but its loading swing is small so circulation goes up. There is still no perfect amine.
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The tool says "required height = 1.4 m" but real columns are 50 m. Why the huge gap?
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Good catch. That 1.4 m is just the mass-transfer height of the packed section (NTU × HTU). A real column adds (1) the inlet plenum and gas distributor (3-5 m), (2) a chimney tray to draw off rich amine (~2 m), (3) demisters and water wash on top (~2 m), and (4) an intercooler (~3 m), then multiplies the lot by a safety factor of about 1.5. That is how 1.4 m becomes 20-30 m or more. Treat the tool value as a lower bound.
FAQ
Take the target capture rate r and compute the number of transfer units NTU = -ln(1-r), then multiply by the height of a transfer unit HTU to get H_required = NTU x HTU. The HTU is approximated as 0.6/reaction-rate-ratio (MEA as base), so faster amines such as KS-1 or piperazine have a smaller HTU. For 90% capture with 30 wt% MEA, NTU is about 2.30 and HTU about 0.6 m, giving a packed height around 1.4 m. Real columns reach 10-30 m once gas distributors, demisters, and a safety margin are added.
MEA 30 wt% is the classic benchmark with balanced kinetics, loading capacity, and reboiler duty around 4.0 GJ/t-CO₂. KS-1 from Kansai Electric / MHI is a sterically hindered amine that drops the duty to about 2.5 GJ/t-CO₂ in exchange for licence fees. Piperazine reacts four times faster but precipitates at high concentration and is usually blended with MDEA. New plants tend to pick KS-1 or MDEA+PZ; retrofits often default to MEA.
Breaking the amine-CO₂ bond requires low-pressure steam at the reboiler — about 4.0 GJ/t-CO₂ for MEA and 2.5 for KS-1. A coal plant gives up 20-30% of its output to that regeneration heat, so the reboiler covers 50-70% of operating cost. A rough capture-cost formula is 40 + reboiler_duty x 8 [USD/t-CO₂], so MEA costs about $72/t and KS-1 about $60/t; cutting 1 GJ of duty saves about $8/t.
Amine flow drives the size of the lean/rich exchanger, reboiler, and pumps. The tool estimates it as C = captured CO₂ / (capacity × 0.3); typical MEA values for 100 t-CO₂/h capture are 500-800 t/h. Above 2,000 t/h, pumping alone costs several MW. Switching to higher-capacity amines such as KS-1 (6 mol/kg) or PZ (8 mol/kg) cuts circulation by 30-50%.
Real-world applications
Coal-fired power plant retrofits: Petra Nova (Texas, 240 MW equivalent, 2017) and Boundary Dam (Saskatchewan, 110 MW, 2014) are the flagship references. Both used KS-1-class solvents and captured 4,500-5,400 t-CO₂/day for enhanced oil recovery. Set the tool to 12-15% CO₂, 90% capture, and KS-1 and you reproduce their published numbers — about 2.5 GJ/t-CO₂ reboiler duty and roughly $60/t levelised capture cost.
Cement plant decarbonisation: Cement-kiln flue gas is 20-30% CO₂, which is unusually favourable for amine absorption because the driving force is high. HeidelbergCement's Brevik plant in Norway, operating from 2024, captures 400,000 t-CO₂/year on an MEA-based loop. Raise the CO₂ slider to 25% and you see the column diameter shrink and the reboiler duty becomes partly coverable by waste heat from the kiln preheater. Steel-mill blast-furnace gas (22% CO₂) is a similar target.
Blue hydrogen front-end: Steam methane reformers can be paired with 90%+ CO₂ capture to produce "blue" hydrogen. The shifted reformer gas is 15-20% CO₂ at 1-3 MPa, so physical solvents (Selexol, Rectisol) compete, but at lower pressure amines still win. Push the pressure slider to 150-200 kPa and the CO₂ slider to 18% to get a first cut for that duty.
Teaching and screening tool: Process and chemical engineering courses can use this tool to introduce the NTU-HTU method and the Kremser equation before students touch Aspen Plus or ProMax. It is also handy as a screening baseline for a "novel amine economics" study — run your solvent's reaction-rate ratio, capacity, and reboiler duty here first, and only fall back to a full simulator once you know which lever matters most.
Common mistakes and caveats
The biggest myth is that CCS is just a bolt-on filter for an existing stack. It is really a full chemical plant: a 500 MW unit needs $500M-$1B of additional capex, plus footprint comparable to the boiler island, plus a long-distance pipeline to a geological storage site. Suitable storage geology is concentrated around the US Gulf Coast, the North Sea, parts of Australia, and a few Japanese sites such as Tomakomai. Treating CCS as a cheap add-on usually leads to capex estimates that are 3-5x too low.
The second trap is chasing the lowest reboiler duty at all costs. KS-1 and CANSOLV really do beat MEA on regeneration heat, but they can be worse on (1) licence fees, (2) degradation rate, (3) corrosion, and (4) atmospheric amine emissions. Piperazine, for example, reacts beautifully but precipitates above 40 wt% — a real plant in a cold climate has plugged its piping because of this. Never select an amine on this tool's reboiler-duty figure alone; check vendor corrosion and degradation data alongside it.
The third trap is assuming that chasing 99% capture is always greener. NTU = -ln(1-r) doubles when r goes from 90% to 99% (2.3 → 4.6), so the packed height roughly doubles, amine circulation and reboiler duty rise with it, and capture cost can grow 1.5-2x. The IEA's analysis shows the last 5% of capture costs about as much as the first 90%. Sweep this tool from 90 → 95 → 99% to see the curve bend upward — most commercial designs deliberately stop near 90-95%.
How to Use
Enter flue-gas volumetric flow rate (m³/h) from your source: coal power plant (40,000–120,000 m³/h), steel mill (15,000–60,000 m³/h), or cement kiln (8,000–35,000 m³/h).
Set inlet CO₂ concentration (vol%) typical for your process: post-combustion power (3–4%), steel BOF exhaust (8–12%), cement calciner (14–18%).
Define target capture rate (70–95%) and absorber inlet gas temperature (40–65 °C); adjust packed-height and solvent circulation to meet energetic and economic constraints.
Temperature approach: gas cooling to 35–40 °C boosts CO₂ equilibrium absorption but increases condenser duty; steel mills often skip pre-cooling due to hot exhaust (140–180 °C pre-treatment).
Solvent degradation: MEA loses 2–4% capacity annually; hotter gas, acid gases (NOx, SO₂), and oxygen accelerate oxidation—install pre-scrubbers for cement/steel sources.
Packing selection: Mellapak 250.Y (structured) suits high-throughput power plants; random Raschig rings reduce fouling in dusty mill exhaust but require taller towers (25–30 m).
Reboiler steam: at 90% capture and 3–4 vol% CO₂, expect 3.5–4.2 MWth per 100 t/h CO₂ captured; co-locate with industrial furnace for waste heat recovery to cut net cost to $35–45/t.