cracking the ccus code: why purity trumps everything

13-Jul-25

Why these notes exist

I spent years in process‑engineering roles, reading heat‑and‑mass balances and FEED packages. To stop re‑learning the same lessons I wrote a private reference on capture projects. This public version is a purity‑based shortcut: three buckets, headline cost bands, and a scan of every major Canadian development. A fund or developer can triage opportunities in minutes, then dive into line items only for the survivors.

💡 Two‑minute investor takeaway

Everything starts with inlet CO₂ purity.

Bucket Purity guide Typical capture scope Indicative cost band*
High‑concentration ≥ 90% Dehydration, compression only 6‑32 USD t⁻¹
(5.6 USD extreme CTL low)
Industrial 5‑25% Full solvent or sorbent island, plus steam 50‑120 USD t⁻¹
Power 3‑15% Solvent system plus turbine or boiler integration 70‑130 USD t⁻¹

* Excludes transport and storage. Most “average capture cost” claims mix these buckets and hide the spread.

1. The three purity buckets

The inlet CO₂ percentage, not the fuel, dictates separation physics and cost. A 94% CO₂ vent from an ammonia plant belongs with ethanol and gas‑processing streams, even though natural gas is the upstream fuel.

2. Quick‑reference cheatsheet

Compression dominates Cost band 6‑32 USD t⁻¹

Archetype Typical hardware Key cost driver
Natural‑gas treating Dehydrator, three‑stage compressor Compressor CAPEX
Ammonia plant vent Same Electricity for compression
Ethanol fermentation Blower, dryer, compressor Dryer utilities
Ethylene oxide vent Dryer, compressor Utility power

Default compression electricity: 100 kWh t⁻¹ (80‑120 range).

Active examples

  • Weyburn–Midale EOR, 95% inlet
  • Cenovus Lloydminster ethanol CCS, 99% (bio)
  • NWR Sturgeon refinery, gasifier AGR stream, ≈ 94%
  • ACTL trunk line, multiple ≥ 90% sources

Solvent island plus steam Cost band 50‑120 USD t⁻¹

Archetype Hardware Integration pinch point
Cement kiln Amine absorber, dust filters 1.5‑2.5 GJ t⁻¹ steam
Refinery SMR flue Amine plus NOₓ trim Steam‑export tie‑in
Blast furnace VPSA or amine Large ductwork
High‑pressure SMR syngas (15‑20% at 30 bar) Rectisol or MDEA, compressor Electricity for refrigeration or pumps

Shell Quest’s 17% SMR flue gas sits here, not in high‑concentration.

Active examples

  • Shell Quest CCS, 17% inlet
  • Heidelberg (Lehigh) Edmonton, 15% kiln gas
  • Suncor–ATCO blue hydrogen, 18% high-pressure syngas

Solvent plus turbine or boiler mods Cost band 70‑130 USD t⁻¹ (retrofit)

Archetype Hardware Main penalty
Pulverised‑coal unit Amine with steam bleed Turbine derate
NGCC Large absorber, big ID fan 10‑20% output drop
OTSG in oil sands Post‑combustion loop Heat‑recovery limit

Active examples

  • Boundary Dam Unit 3, 12‑15% lignite flue
  • Pathways Alliance hub, 3‑5% OTSG exhaust
  • Advantage Glacier Phase 1, 3‑4% turbine exhaust

3. Decision flow : purity first, everything else second

flowchart TD
    A[Measure inlet CO₂] -->|≥ 90%| HC[High‑conc sheet]
    A -->|5‑25%| IND[Industrial sheet]
    A -->|3‑15%| POW[Power sheet]
    HC --> SCOPES[Compression only]
    IND --> SCOPES2[Solvent + steam]
    POW --> SCOPES3[Solvent + integration]

Rule: Purity decides the bucket, even if the plant burns natural gas. Air Products Edmonton burns gas in its ATR, yet its shifted syngas is only 18% CO₂, so it lives in the Industrial sheet.

4. Canadian project tracker, July 2025

High‑concentration (≥ 90% CO₂)

Project Stream Status Note
Bow River Carbon Hub NGL extraction, ≥ 90% Operating Backbone for ACTL
Cenovus Lloydminster Ethanol vent, 99% Operating Bio‑CO₂
Co‑op Ethanol Complex Fermentation vent, 99% Plan 0.25 Mt y⁻¹
NWR Sturgeon Gasifier AGR tail, 94% Operating 1.3 Mt y⁻¹
Saskatchewan NET‑Power Allam cycle exhaust, 97% Early Oxy‑fuel demo

Industrial (5‑25% CO₂)

Project Stream Status Note
Heidelberg (Lehigh) Edmonton Kiln gas, 15% FEED 1 Mt y⁻¹ target
Shell Quest SMR flue, 17% Operating Debottleneck study
Air Products Edmonton ATR syngas, 18% at 30 bar Build 1.5 Mt y⁻¹
Suncor–ATCO blue hydrogen SMR syngas, 18% at 25 bar FEED 2 Mt y⁻¹
Tidewater blue hydrogen Shifted syngas, 18% Early 0.8 Mt y⁻¹
Dow Fort Sask Cracker off‑gas, 10% FEED Path2Zero program
Teck Trail Smelter off‑gas, 10% Study Non‑ferrous metals

Power (3‑15% CO₂)

Project Stream Status Note
Pathways Alliance hub OTSG flue, 3‑5% FEED 10+ Mt cluster
Boundary Dam Unit 3 Coal flue, 12‑15% Operating First‑of‑kind
Caroline CCS power New NGCC, 3‑4% Plan Greenfield with CCS
TransAlta large‑scale NGCC retrofit, 3‑4% Study 2.5 Mt y⁻¹
Advantage Glacier Phase 2 Gas turbine, 3‑4% FEED 0.16 Mt y⁻¹
Hinton BECCS Biomass boiler, 12% Study Negative emissions

5. Two flagship case studies

Heidelberg Cement, Edmonton kiln : Industrial bucket

  • Capex drivers: two 12 m absorbers, 100 MW auxiliary boiler, eight‑stage compressor
  • Steam duty: 3 GJ t⁻¹ (advanced solvent target 2.6 GJ t⁻¹)
  • Levelised capture cost: ≈ 80‑100 USD t⁻¹ if steam is fired on natural gas
  • Schedule risk: retrofit of a 1950s kiln in 36 months, carry contingency

Suncor–ATCO blue hydrogen : Industrial, high-pressure sub‑class

  • Inlet stream: 18% CO₂ at 25 bar, high partial pressure cuts solvent duty
  • Capture block: Rectisol plus eight‑stage compressor, no steam extraction
  • Expected cost: 25‑45 USD t⁻¹ (below bulk industrial average yet above pure‑compression cases)
  • Electricity: 100‑120 kWh t⁻¹, lock a low‑carbon PPA to protect scope 2 emissions

6. Typical line‑item breakdowns

Item Heidelberg 1 Mt y⁻¹ Suncor–ATCO 2 Mt y⁻¹
Absorber trains 190 M USD n/a
Solvent regeneration 70 M USD n/a
Auxiliary boiler 85 M USD n/a
Eight‑stage compressor 65 M USD 100 M USD
Dehydration skid n/a 10 M USD
Balance, contingency 229 M USD 40 M USD
Total CAPEX 639 M USD ≈ 170 M USD
Steam duty 3 GJ t⁻¹ none
Compression electricity 110 kWh t⁻¹ 120 kWh t⁻¹

7. Modelling checklist

  1. Break every project into installed line items, never a single USD t⁻¹ number.
  2. Link steam duty to a live fuel‑price cell.
  3. Use 80‑120 kWh t⁻¹ as the compression band; default 100 kWh t⁻¹.
  4. Expose sliders for capture rate, electricity price, capacity factor.
  5. After the maths, roll assets into the purity buckets for portfolio graphics.

8. Projects that could move with a policy nudge

Project Stream What unlocks it
Fort Nelson gas plant 2.2 Mt pure CO₂ BC‑style carbon contract for difference
Bethune potash mine 1 Mt, 6‑10% Waste‑heat integration plus milestone grant
Lafarge Bath cement Mineralisation pilot Federal production credit top‑up
Algoma Steel Blast furnace, 20% Concessional debt bridging to green DRI

9. Category definitions, one‑pager

Characteristic High‑concentration Industrial Power
Inlet CO₂ ≥ 90% 5‑25% 3‑15%
Typical hardware Compressor only Solvent + steam Solvent + turbine mods
Indicative cost 6‑32 USD t⁻¹ 50‑120 USD t⁻¹ 70‑130 USD t⁻¹
Compression electricity 80‑120 kWh t⁻¹ Same plus steam Same plus fan power
Active Canadian examples Weyburn, ACTL trunk Heidelberg, Quest, blue H₂ Boundary Dam, Pathways

About these notes: Feedback is welcome, especially on inlet‑gas assays or updated FEED numbers. Send corrections or data points and I will roll them into the next quarterly update. Made with <3 in Alberta.