1. Overview
Post-combustion CCUS is the most mature and widely-deployed approach to large-scale CO₂ capture. The technology extracts CO₂ from the flue gas of an existing or new combustion source (power plant, cement kiln, steel mill, refinery) — after combustion has occurred but before the gas reaches the stack. The captured CO₂ is then compressed and transported via pipeline to permanent storage in geological formations (saline aquifers, depleted reservoirs) or to enhanced oil recovery (EOR) projects.
Three operating commercial-scale post-combustion facilities (as of 2024):
| Project | Source | Capacity | Solvent | Online |
|---|---|---|---|---|
| Boundary Dam Unit 3 (SaskPower) | Coal-fired power plant | 1.0 Mtpa CO₂ | Cansolv (Shell) | 2014 |
| Petra Nova (NRG) | Coal-fired power plant | 1.6 Mtpa CO₂ | KS-1 (MHI) | 2017 |
| Drax BECCS pilot (UK) | Biomass-fired power plant | 0.005 Mtpa pilot | Various | 2019 |
| Standard / Reference | Scope |
|---|---|
| DOE NETL Cost & Performance Baseline (2022) | Reference cost and performance for NGCC, USC coal, IGCC with CCUS |
| IEAGHG Technical Reports | Detailed CCUS process and economic studies (2014, 2017, 2020) |
| IPCC Special Report on CCS (2005) | Foundational technology assessment |
| ISO 27914:2017 | CO₂ geological storage (downstream of capture) |
| IRS §45Q (post-IRA 2022) | US Federal tax credit for sequestered CO₂ |
| EU CCS Directive 2009/31/EC | European regulatory framework for CCS deployment |
2. Process Description
The standard amine post-combustion capture process consists of:
- Direct Contact Cooler (DCC): Cools flue gas from ~150 °C (boiler exit) to ~40 °C, condenses water, removes some particulates. Flue gas SO₂ is also removed if not already polished by upstream FGD.
- Absorber: Lean amine solvent (low CO₂ loading) contacts cooled flue gas in a counter-current packed tower. CO₂ is absorbed via reversible chemical reaction. Treated flue gas (90%+ CO₂ removed) exits to stack.
- Lean/Rich Heat Exchanger: CO₂-rich solvent (high loading) is preheated by hot lean solvent returning from the regenerator — recovers about 60% of regenerator heat duty.
- Stripper / Regenerator: Rich solvent enters the top of a packed column. Reboiler at the bottom heats the solvent to ~120 °C, reversing the CO₂ absorption reaction and releasing pure CO₂ + water vapor at the top.
- Reflux: Top vapor cooled in condenser; water reflux returns; pure CO₂ exits at ~95–99% purity.
- CO₂ compression: Multi-stage compression (4–6 stages) from regenerator outlet (~1.5 bara) to dense-phase pipeline conditions (150 bara).
Process flow diagram (text representation)
Flue gas → DCC → Absorber → CO₂-lean flue to stack
↓
Rich amine
↓
Lean/Rich HX (cross-exchange)
↓
Stripper
↑ ↓
Reboiler steam Lean amine (cooled, recycled to absorber top)
↓
CO₂ at 1.5 bara → Compression Train → Pipeline at 150 bara
Key process variables
| Parameter | Typical range | Driver |
|---|---|---|
| Flue gas CO₂ content | 4–15 mol% | Source: NGCC ~4%, USC coal ~13%, cement ~25% |
| Capture rate | 85–99% | Set by absorber height + L/G ratio |
| Lean loading | 0.10–0.32 mol CO₂/mol amine | Set by stripper severity |
| Rich loading | 0.40–0.50 mol CO₂/mol amine | Equilibrium with absorber bottom CO₂ partial P |
| Solvent circulation rate | set by capture × Δloading | Lower = less pumping but smaller absorber |
| Reboiler temperature | 110–125 °C | Set by solvent vapor pressure + degradation limit |
| Reboiler steam pressure | 3–5 bara saturated | Extracted from LP turbine |
3. Solvent Chemistry
Post-combustion CO₂ capture uses aqueous solvents that react reversibly with CO₂:
Primary amine reaction (MEA):
CO₂ + 2 R-NH₂ ⇌ R-NHCOO⁻ + R-NH₃⁺ (carbamate formation)
Stoichiometry: 2 mol amine per mol CO₂
Reaction enthalpy: ~84 kJ/mol CO₂ (high; drives regeneration energy)
Loading limit: ~0.5 mol CO₂/mol amine
Tertiary amine (MDEA):
CO₂ + R₃N + H₂O ⇌ R₃NH⁺ + HCO₃⁻ (bicarbonate formation, slow)
Stoichiometry: 1 mol amine per mol CO₂
Reaction enthalpy: ~50 kJ/mol CO₂ (lower; less regen energy)
Loading limit: ~1.0 mol CO₂/mol amine
Slow kinetics — needs activator for fast absorption
Promoted MDEA (MDEA-PZ blend):
PZ provides fast absorption kinetics; MDEA provides high loading capacity
Industry solvents
| Solvent | Regen energy (GJ/tCO₂) | Concentration | Notes |
|---|---|---|---|
| MEA (monoethanolamine) | 3.7 | 30 wt% | Industry baseline; benchmark for all comparisons |
| MDEA (methyldiethanolamine) | 4.2 | 40 wt% | Lower regen but slow kinetics; needs PZ activator |
| Piperazine (PZ) | 2.5 | 40 wt% | Fast kinetics, high capacity; concentrated PZ pioneered by Rochelle |
| MDEA-PZ blend (KS-1, OASE blue) | 3.0 | 45 wt% total | Best of both worlds; commercial in Petra Nova, Boundary Dam (Cansolv) |
| Advanced (CESAR-1, KM-CDR) | 2.2–2.7 | various | Newer formulations targeting < 2.5 GJ/t |
Solvent degradation
Amine solvents degrade in service via three primary mechanisms:
- Thermal: at reboiler temperatures > 125 °C, amines undergo carbamate polymerization → heavy compounds that build up in the system
- Oxidative: trace O₂ in flue gas oxidizes amines to organic acids (e.g., glycolic acid, formate) — most severe for MEA
- SOx / NOx attack: residual SO₂ forms heat-stable salts; NOₓ contributes to nitrosamine formation
Make-up rate for MEA: 1.5–3 kg/tCO₂ captured. Reclaiming systems (thermal or ion exchange) extract degraded amine for disposal and recover undegraded amine. PZ has notably better degradation resistance than MEA.
The MEA baseline: 30 wt% MEA is the industry reference solvent because it has been studied for > 50 years and used in dozens of commercial natural-gas treating units. Its regen energy of 3.7 GJ/tCO₂ is the standard against which newer solvents are benchmarked. Modern projects rarely choose MEA because of its high regen energy and degradation, but every solvent vendor compares to MEA in their datasheets.
4. Regeneration Energy
Solvent regeneration is the single largest energy cost in post-combustion CCUS. The reboiler heat duty has three components:
Qreboiler = Qheat-of-reaction + Qsensible + Qvapor
Qheat-of-reaction: energy to reverse CO₂-amine bond formation
(~ 40–60% of total)
Qsensible: heat solvent from cold-rich to reboiler T
(~ 20–30% of total; partly recovered in lean/rich HX)
Qvapor: latent heat of water vaporization at top of stripper
(~ 20–30% of total)
Total typical: 2.5–4.2 GJ/tCO₂ depending on solvent
Steam consumption
The reboiler is heated with low-pressure steam (typically 4 bara saturated, T_sat ≈ 144 °C). Steam latent heat at 4 bara: 2,133 kJ/kg.
Steam consumption = Qregen × 1e6 / hlatent
For 90% capture of 100 t/h CO₂ with MEA (3.7 GJ/t):
Qregen = 90 × 3.7 = 333 GJ/h = 92.5 MW thermal
Steam = 333 × 1e6 / 2133 = 156,140 kg/h = 156 t/h
Solvent circulation rate
Lean amine flow rate is set by mol-balance:
m_dot_amine [kmol/h] = m_dot_CO₂_captured / (rich_loading − lean_loading)
For 90 t/h CO₂ captured with MEA Δloading = 0.30 mol/mol:
CO₂ captured = 90 × 1000 / 44.01 = 2045 kmol/h
Amine = 2045 / 0.30 = 6818 kmol/h
Mass amine = 6818 × 61.08 = 416,400 kg/h
Solution at 30 wt%: 416,400 / 0.30 = 1,388,000 kg/h
Volumetric (~ water density): ~ 1,388 m³/h
Auxiliary power
Beyond reboiler heat, electrical auxiliaries consume:
| Auxiliary | Specific energy | Notes |
|---|---|---|
| CO₂ compressor (5-stage to 150 bara) | 0.10–0.12 MWh/tCO₂ | DOE NETL average |
| Solvent pumps (lean + rich) | 0.02–0.04 MWh/tCO₂ | Largest pump on the plant |
| Flue gas blower | 0.01–0.02 MWh/tCO₂ | Overcomes absorber pressure drop |
| Cooling water pumps | 0.005–0.01 MWh/tCO₂ | Substantial cooling load |
| Total auxiliary | ~ 0.45 MWh/tCO₂ | DOE NETL composite |
Compute regeneration energy and OPEX
→ D22: Post-Combustion Amine Capture Energy5. Parasitic Load on Power Plants
For a power plant retrofit (or new-build with capture), the CCUS unit imposes a "parasitic load" — energy diverted from electrical generation to capture operations. The total parasitic has three components:
- Reboiler steam extraction loss: Steam diverted from the LP turbine reduces electrical output. Conversion factor ~0.20 MWh_e lost per GJ_thermal extracted.
- CO₂ compression power: Direct electrical load on plant aux power.
- Auxiliary power: Pumps, blowers, cooling water for capture process.
Total parasitic [MW_e] = steam_loss + compression + auxiliary
steam_loss = m_dot_CO₂ × regen_GJ_t × 0.20
(0.20 MWh_e/GJ_th — LP steam extraction equivalent)
compression = m_dot_CO₂ × 0.110 (MWh/tCO₂)
auxiliary = m_dot_CO₂ × 0.040 (MWh/tCO₂)
Net plant efficiency
ηwith CCS = (gross_MW − parasitic) / fuel_thermal_MW
η drop in percentage points = ηbaseline − ηwith CCS
DOE NETL baseline performance with CCUS
| Plant type | Baseline η | η with 90% CCUS | η drop (pp) | Power loss (% gross) |
|---|---|---|---|---|
| NGCC (advanced F-class) | 56.2% | 47.4% | 8.8 | 15.7% |
| USC pulverized coal | 40.4% | 30.0% | 10.4 | 25.7% |
| SC pulverized coal | 38.6% | 28.2% | 10.4 | 26.9% |
| Subcritical pulverized coal | 36.4% | 25.5% | 10.9 | 30.0% |
| Cement (industrial) | N/A (heat-only) | N/A | N/A | ~ 25% MJ/kg cement penalty |
Why higher penalty for coal vs gas
Coal plants suffer larger η drops than NGCC because:
- Higher CO₂ flue gas content (13% vs 4% for NGCC) → more CO₂ to capture per MWh
- More fuel-bound C atoms per MJ thermal (carbon intensity 340 vs 198 kg/MWh_th)
- Lower baseline efficiency means proportionally larger parasitic load
Compute parasitic load for your plant
→ D23: CCUS Parasitic Load Calculator6. Levelized Economics
The full-chain cost of CCUS combines capture, transport, and storage:
LCO_CO₂ = (annualized_CAPEX + OPEX + transport + storage) / annual_tonnes
Annualized CAPEX uses Capital Recovery Factor:
CRF = r·(1+r)n / ((1+r)n − 1)
where r = discount rate, n = plant lifetime
$/tCO₂ avoided = LCO_CO₂ × (1 − parasitic_emissions_pct)
(avoids count parasitic CO₂ from grid power for compression)
DOE NETL 2022 cost baselines
| Source | $/tCO₂ avoided | Capture CAPEX | Capture OPEX |
|---|---|---|---|
| NGCC retrofit (90% capture) | $58 | $650/t-yr | $28/tCO₂ |
| USC coal new build (90% capture) | $58 | $700/t-yr | $32/tCO₂ |
| USC coal new build (95% capture) | $67 | $750/t-yr | $36/tCO₂ |
| Refinery (NG-fired heater) | $50–80 | $500–800/t-yr | $25–40/tCO₂ |
| Cement (calciner) | $80–120 | $1000+/t-yr | $40–60/tCO₂ |
| Steel (BF/BOF integrated) | $80–150 | $1000+/t-yr | $40–80/tCO₂ |
| DAC (saline storage) | $200–600 | $3000+/t-yr | $150–400/tCO₂ |
Transport and storage
| Component | Typical range | Notes |
|---|---|---|
| Pipeline transport | $1–3 / tCO₂ / 100 km | NPC 2019; smaller pipes / shorter distances at high end |
| Saline storage (incl. MMV) | $5–25 / tCO₂ | DOE NETL; includes wells, monitoring, post-injection liability |
| EOR storage | $0–20 / tCO₂ | Often net negative when oil revenue counted |
45Q tax credit framework (post-IRA)
| Sequestration type | $/tCO₂ | Construction-start deadline |
|---|---|---|
| Saline storage (industrial / power) | $85 | Jan 1, 2033 |
| EOR storage | $60 | Jan 1, 2033 |
| Direct Air Capture, saline storage | $180 | Jan 1, 2033 |
| Direct Air Capture, EOR | $130 | Jan 1, 2033 |
Credit duration: 12 years from project commissioning. Monetization options: claim against tax liability (default), direct-pay election (3-year), or transferability.
Net economics with 45Q: For an NGCC retrofit at $58/tCO₂ levelized cost, the $85/tCO₂ saline-storage tax credit produces a net +$27/tCO₂ — meaning the project pays the operator to capture CO₂. This is the policy mechanism designed to drive CCUS deployment in the US through 2033. Even high-cost industrial sources ($80–120/tCO₂) become marginally profitable at $85 credit.
Run full-chain CCUS economics
→ D25: CCUS Capture Economics Calculator7. Worked Example
Problem: A 500 MW NGCC power plant is retrofitted with 90% post-combustion capture using PZ-promoted MDEA. Compute regeneration energy, parasitic load, and levelized $/tCO₂ avoided.
Step 1: CO₂ source rate.
NGCC at 56% gross efficiency, CH₄-fired
Fuel input = 500 / 0.56 = 893 MW thermal
CO₂ emission factor ≈ 198 kg CO₂/MWh thermal (NG combustion)
CO₂ rate = 893 × 0.198 = 177 t/h baseline
Captured (90%) = 177 × 0.90 = 159 t/h CO₂
Annual: 159 × 8760 = 1.39 Mtpa CO₂ captured
Step 2: Regeneration energy.
PZ-MDEA solvent: 3.0 GJ/tCO₂
Qregen = 159 × 3.0 = 477 GJ/h = 132 MW thermal
Steam at 4 bara: 132 × 1e6/2133 ≈ 62 t/h LP steam
Step 3: Parasitic load.
Steam extraction loss = 132 × 0.20 = 26.4 MW_e
CO₂ compression = 159 × 0.110 = 17.5 MW_e
Auxiliary (pumps, blower, cooling) = 159 × 0.040 = 6.4 MW_e
Total parasitic = 50.3 MW_e
Net with CCS = 500 − 50.3 = 449.7 MW
η_baseline = 56.0%
η_with CCS = 449.7 / 893 = 50.4%
η drop = 5.6 pp (modest, because PZ-MDEA chosen vs MEA)
Step 4: CAPEX-amortized cost.
Capture CAPEX = $650/t-yr × 1,390,000 t/yr = $904 million
Lifetime 25 yr, discount rate 8%:
CRF = 0.08·(1.08)25 / ((1.08)25 − 1) = 0.0937
Annualized = $904M × 0.0937 = $84.7M/yr
$/tCO₂ from CAPEX = $84.7M / 1.39M t = $61/t
Step 5: Total levelized cost.
Capture OPEX = $28/tCO₂ × 1.39M = $38.9M/yr
Transport (100 km × $2/t/100km) = $2/t × 1.39M = $2.8M/yr
Storage = $10/t × 1.39M = $13.9M/yr
Total annual = $84.7M + $38.9M + $2.8M + $13.9M = $140.3M/yr
$/tCO₂ captured = $140.3M / 1.39M = $100.9/tCO₂
Parasitic emissions ≈ 10% (compression power on grid)
$/tCO₂ avoided = $100.9 / (1 − 0.10) = $112/tCO₂
Step 6: 45Q netting.
Annual 45Q revenue (saline, $85/t) = $85 × 1.39M = $118.2M/yr
Net annual cost = $140.3M − $118.2M = $22.1M/yr
Net $/tCO₂ avoided = $22.1M / (1.39M × 0.9) = $17.7/tCO₂
Result: Without 45Q, $112/tCO₂ avoided is well above market voluntary carbon credits ($5-30/t) and not commercially viable. With 45Q, net $17.7/tCO₂ is profitable — the operator collects more from the tax credit than they spend on the project. This is why the 2022 Inflation Reduction Act unlocked the US CCUS pipeline (50+ projects announced post-IRA).
Run this full-chain analysis
→ D25: CCUS Capture Economics Calculator8. Standards & References
- DOE NETL Cost and Performance Baseline for Fossil Energy Plants (2022) — Vol 1: Bituminous Coal & NG to Electricity
- IEAGHG Technical Reports: 2014/4 (CO₂ Pipeline Infrastructure), 2017/8 (Update on PCC), 2020/12 (CCUS Cost & Performance)
- IPCC Special Report on Carbon Dioxide Capture and Storage (2005, updated chapters 2018)
- ISO 27914:2017, Carbon dioxide capture, transportation and geological storage — Geological storage
- ISO 27913:2016, CO₂ pipeline transportation systems
- IRS Internal Revenue Code §45Q (post-Inflation Reduction Act of 2022)
- EU Directive 2009/31/EC on the geological storage of carbon dioxide
- Rochelle, G.T. (2009). "Amine Scrubbing for CO₂ Capture," Science 325, 1652–1654.
- Rochelle, G.T. (2022). "Conventional amine scrubbing for CO₂ capture," in Absorption-Based Post-combustion Capture of Carbon Dioxide, Woodhead Publishing.
- NPC (2019). "Meeting the Dual Challenge: A Roadmap to At-Scale Deployment of Carbon Capture, Use, and Storage."
- Bui, M. et al. (2018). "Carbon capture and storage (CCS): the way forward," Energy Environ. Sci. 11, 1062–1176.
- Boundary Dam Carbon Capture Project, SaskPower (operating 2014–present)
- Petra Nova Carbon Capture Project, NRG/JX Nippon (operating 2017–2020, restarted 2024)