🎓 Lesson 11
D5
Case Review: Amine-Based Flue Gas CO₂ Capture
Amine-based CO₂ capture is a chemical process that uses special liquids (amines) to grab carbon dioxide from power plant exhaust gases, like a sponge soaking up water.
🎯 Learning Objectives
- ✓ Calculate CO₂ loading capacity and theoretical minimum solvent flow rate using equilibrium and material balance principles
- ✓ Design a packed absorber column by determining height equivalent to a theoretical plate (HETP) and number of transfer units (NTU) for a given flue gas composition and removal target
- ✓ Analyze energy consumption of the regeneration step using heat duty calculations and steam-to-CO₂ ratios
- ✓ Explain the trade-offs between solvent concentration, circulation rate, and degradation in amine systems
- ✓ Apply mass transfer correlations (e.g., O'Connell, Billet) to estimate pressure drop and flooding limits in industrial-scale absorbers
📖 Why This Matters
Global coal- and gas-fired power plants emit ~12 gigatonnes of CO₂ annually—nearly one-third of global energy-related emissions. Amine-based capture remains the only commercially deployed post-combustion technology capable of retrofitting existing plants without major infrastructure overhaul. For mining engineers involved in integrated energy systems (e.g., remote mine power generation, smelter off-gas treatment), understanding this process is critical for lifecycle decarbonization planning, ESG compliance, and evaluating carbon credit opportunities. It also underpins emerging applications like direct air capture (DAC) and mineral carbonation feedstock supply.
📘 Core Principles
Amine absorption relies on reversible acid–base chemistry: CO₂ dissolves in water, forms carbonic acid, and reacts with protonated amines to yield carbamates (for primary/secondary amines) or bicarbonate (for tertiary amines). The reaction kinetics, equilibrium loading (mol CO₂/mol amine), and heat of reaction govern process design. Absorption occurs in a counter-current packed column where flue gas (typically 4–15% CO₂, 3–7% O₂, balance N₂) contacts lean solvent at ~40–50°C; stripping occurs at 100–120°C under reduced pressure or with steam stripping. Key design constraints include solvent volatility (MEA loss), oxidative/thermal degradation (forming heat-stable salts), corrosion (requiring metallurgy upgrades), and parasitic energy demand (~2.0–3.5 GJ/tonne CO₂ captured).
📐 Minimum Solvent Flow Rate
The theoretical minimum solvent flow rate (L_min) is derived from equilibrium and overall material balance at the absorber pinch point, where the lean solvent composition intersects the equilibrium curve at the top of the column. It sets the lower bound for economic operation—real designs use L = 1.2–1.5 × L_min to ensure adequate driving force.
💡 Worked Example
Problem: Given: Flue gas flow = 100 kmol/h, CO₂ mole fraction = 0.12, target removal = 90%. Equilibrium CO₂ loading of 30 wt% MEA at lean condition = 0.25 mol CO₂/mol MEA; rich loading limit = 0.45 mol CO₂/mol MEA.
1.
Step 1: Calculate CO₂ inlet = 100 × 0.12 = 12 kmol/h; CO₂ captured = 12 × 0.9 = 10.8 kmol/h.
2.
Step 2: Apply material balance: L_min × (0.45 − 0.25) = 10.8 → L_min = 10.8 / 0.20 = 54 kmol MEA/h.
3.
Step 3: Convert to mass flow: MEA MW = 61 g/mol → 54 × 61 = 3294 kg/h. Compare to typical 30 wt% MEA solution density ≈ 1040 kg/m³ → ~3.2 m³/h minimum solvent volume flow.
Answer:
The minimum solvent flow rate is 54 kmol MEA/h (3294 kg/h), which corresponds to ~3.2 m³/h of 30 wt% solution. Real design would specify 65–80 kmol/h (L/L_min ≈ 1.2–1.5) to ensure >90% removal with <10 kPa pressure drop.
🏗️ Real-World Application
The Boundary Dam Power Station Unit 3 (Saskatchewan, Canada) was the world’s first commercial-scale post-combustion amine capture retrofit (2014). Using chilled MDEA-based solvent, it captures ~1 MtCO₂/year from a 115 MW coal unit. Key engineering adaptations included: (1) flue gas cooling from 120°C to 40°C via an induced-draft cooler and quench tower; (2) corrosion-resistant stainless-steel internals (AL-6XN) in absorber/stripper; (3) a 3-stage solvent filtration system to remove heat-stable salts; and (4) integration with SaskPower’s CO₂ pipeline to Weyburn oil field for EOR. Operational data shows average steam demand of 3.3 GJ/tonne CO₂ and solvent degradation rate of 0.8 kg/tonne CO₂—well within design specs per IEA CCS Guidelines.
🔧 Interactive Calculator
🔧 Open Mass Transfer and Separation Processes Calculator📋 Case Connection
📋 Ethanol-Water Separation in Biofuel Plant
High energy demand for azeotropic distillation; poor purity (<92%) in first-pass product
📋 CO₂ Capture from Flue Gas using Amine Absorption
Low CO₂ partial pressure (~0.15 bar); amine degradation and solvent carryover