CO2 injection

CO2 injection in the oil and gas industry is the deliberate subsurface delivery of carbon dioxide, either as a compressed gas, a dense-phase liquid, or a supercritical fluid (above the critical point of 31.1 degrees Celsius and 7.38 MPa), into a porous reservoir formation through a purpose-designed injection well, for the dual purposes of enhanced oil recovery (CO2-EOR) and geological carbon storage (GCS); in CO2-EOR, injected CO2 contacts residual and bypassed oil, reducing oil viscosity by 10 to 80 percent, swelling oil volume by 5 to 25 percent, reducing interfacial tension toward zero at minimum miscibility pressure (MMP), and achieving first-contact or multiple-contact miscibility that produces near-100 percent displacement efficiency in the contacted pore volume, recovering 10 to 20 percent of original oil in place (OOIP) beyond primary and secondary waterflooding; in GCS, CO2 is injected into deep saline aquifers or depleted reservoirs at sufficient depth (typically greater than 800 m) to maintain supercritical conditions where CO2 density of 600 to 800 kg/m3 provides efficient pore-space storage, with long-term trapping provided by structural, residual (capillary trapping), dissolution (CO2 dissolving into brine as carbonic acid), and mineral (carbonate precipitation) trapping mechanisms. In the Western Canada Sedimentary Basin, CO2 injection is practiced commercially at the Weyburn-Midale CO2-EOR and storage project in Saskatchewan (Cenovus and Whitecap Resources, CO2 sourced from the Dakota Gasification Company plant via the Souris Valley pipeline, injecting approximately 2 million tonnes per year into Mississippian Midale carbonates at 1,400 m depth), the Shell Quest CCS project near Fort Saskatchewan (CO2 from the Scotford Upgrader injected into the Basal Cambrian Sands at 2,000 m depth, storing approximately 1 million tonnes per year), and the Alberta Carbon Trunk Line system connecting CO2 from Agrium's Redwater fertilizer plant to heavy oil fields in the Clive and Stettler areas for CO2-EOR in Nisku and Cooking Lake carbonates. AER Directive 065 and AER Directive 051 govern CO2 injection well licensing, pressure authorization, and conformance monitoring in WCSB projects, while Alberta's Carbon Sequestration Tenure Regulation transfers long-term storage liability to the Alberta Crown 10 years post-closure if AER performance standards are met.

• CO2-EOR mechanisms and minimum miscibility pressure in WCSB carbonate reservoirs: The primary mechanism driving incremental recovery in CO2-EOR is multiple-contact miscibility (MCM) achieved when injection pressure exceeds the MMP; for WCSB Midale and Nisku carbonate reservoir oils (API gravity 28 to 38 degrees, C5+ content 40 to 55 percent), MMP ranges from 12 to 18 MPa, within the hydrostatic pressure available at 1,000 to 1,600 m depth. At pressures above MMP, CO2 and reservoir oil exchange components through multiple contacts until the two phases converge to a single miscible phase with zero interfacial tension and pore-scale displacement efficiency approaching 100 percent in the contacted volume. In the Weyburn Unit (Midale Marly and Vuggy dolomite, porosity 14 to 20 percent, permeability 1 to 50 mD), injected CO2 alternates with water in a WAG pattern at a 1:1 to 2:1 ratio cycling every 3 to 6 months to balance mobility control (CO2 viscosity 0.06 mPa-s versus oil at 4 to 12 mPa-s) and maximize contact with bypassed oil; peak incremental oil rates of 5 to 30 m3 per day per producer in the most responsive Marly dolomite intervals are observed 6 to 24 months after CO2 injection begins.
• CO2 injection well design and injectivity in WCSB CO2-EOR and GCS projects: CO2 injection wells must handle the corrosive and phase-change properties of supercritical CO2: with trace water, CO2 forms carbonic acid corroding carbon steel at 0.1 to 10 mm/year depending on water content and temperature, requiring 13Cr or 22Cr duplex stainless steel tubing or internally coated carbon steel with dry CO2 (less than 50 ppm water by mole) in WCSB injection wells. Injectivity at Weyburn-Midale wells is typically 5 to 30 tonnes CO2 per day at surface injection pressures of 12 to 18 MPa; injectivity decline from near-wellbore carbonate reprecipitation is managed by periodic 15 percent HCl acid stimulation and maintaining injection pressure above MMP to keep CO2 supercritical through the near-wellbore zone. Well completion designs use packer-and-tubing configurations that isolate CO2 from intermediate casing strings to prevent corrosion of lower-grade steel in the annulus, with downhole safety valves rated for supercritical CO2 service in WCSB regulatory-required well control equipment.
• CO2 geological storage monitoring and verification in WCSB GCS projects: WCSB CO2 GCS projects require comprehensive monitoring, measurement, and verification (MMV) programs confirming that injected CO2 remains within the approved storage complex; at Quest (Basal Cambrian Sands, caprock is the Cambrian Earlie shale at least 100 m thick), MMV uses time-lapse 3D seismic surveys annually, downhole pressure and temperature monitoring in injection and observation wells, soil gas surveys, and atmospheric CO2 flux measurements. The 15-year IEA Weyburn-Midale CO2 Monitoring and Storage Project (2000-2012) established global protocols for storage site characterization, demonstrating that CO2 injected into the Midale remained within the approved reservoir and that the Watrous Formation caprock (50 to 80 m of evaporite and anhydrite) provided effective containment with no CO2 anomaly detected in the overlying Lodgepole Formation. Alberta's CSTR de-risks long-term storage investment by transferring Crown liability after 10 years post-closure if AER performance standards are met, creating a framework for commercial WCSB GCS development.
• CO2 supply, pipeline transportation, and source-sink matching for WCSB projects: WCSB CO2-EOR and GCS viability depends on reliable, low-cost CO2 supply chains connecting industrial sources to storage sinks; the Weyburn project sources CO2 from the North Dakota Gasification Plant (3 million tonnes per year from coal gasification) via the 320 km Souris Valley pipeline at $20 to $30 per tonne CO2 including compression and transport, competitive with CO2-EOR economics at oil prices above $45 to $60 per barrel. The ACTL pipeline (240 km, 14.6 MPa design pressure) connects north-central Alberta CO2 sources to Clive area heavy oil fields with transport costs of $16 to $22 per tonne, supported by Alberta TIER carbon credits and Clean Fuel Regulations compliance credits; total CO2-EOR operating cost on the ACTL is $45 to $65 per tonne at the injection well. The proposed Pathways Alliance CO2 trunk line targeting 22 million tonnes per year from Athabasca oil sands facilities to a Cold Lake storage hub could reduce WCSB injection costs to $15 to $25 per tonne at scale, enabling large-volume WCSB decarbonization alongside continued oil production.
• CO2 injection operational challenges: gravity override, viscous fingering, and corrosion: CO2 injection in WCSB reservoirs faces gravity override (CO2 density 600 to 800 kg/m3 at reservoir conditions is less than brine at 1,000 to 1,050 kg/m3, causing CO2 to migrate upward and bypass lower zones), viscous fingering (CO2 viscosity of 0.04 to 0.08 mPa-s is 50 to 300 times lower than WCSB reservoir oil, creating unstable displacement fronts), and infrastructure corrosion. WAG injection addresses both sweep problems simultaneously: water provides mobility control and gravity stabilization while CO2 achieves miscibility in contacted zones; optimized WAG at Weyburn using 1:1 ratio at 3-month cycles improves areal sweep from 40 to 60 percent (CO2 flood alone) to 60 to 80 percent. Corrosion management at WCSB CO2 facilities uses continuous dew-point monitoring (maintaining water below 50 ppm to prevent free water condensation), chemical injection (corrosion inhibitors at 50 to 100 ppm in surface flowlines), and electrochemical corrosion coupons retrieved quarterly to confirm rates below 0.1 mm/year.

CO2 Injection Restoring WCSB Midale Carbonate Production

A WCSB Midale carbonate unit had declined from 180 m3/day oil at primary peak to 35 m3/day after 20 years of waterflooding, with residual oil saturation estimated at 28 percent OOIP. CO2 injection began with 8 injectors and 12 producers in a 5-spot pattern, injecting CO2 from the Souris Valley pipeline at 14 MPa, above the measured MMP of 12.8 MPa for the 34 API Midale oil. WAG cycles of 3 months CO2 followed by 3 months water were implemented. After 18 months, 6 producers showed incremental oil response averaging 12 m3 per day, bringing total production to 107 m3 per day. Produced CO2 reached 40 percent of injection volume by month 24, requiring a CO2 separation and reinjection plant at $4.2 million capital cost. After 5 years, incremental recovery totaled 185,000 m3 of oil, equivalent to 18 percent of estimated residual OOIP in the flood pattern area, confirming economic viability above $50 per barrel oil.

Related Terms

Enhanced oil recovery (EOR) encompasses CO2 injection as the primary miscible flood method in WCSB carbonate reservoirs; CO2-EOR recovers 10-20 percent additional OOIP beyond waterflooding when injection exceeds MMP. Minimum miscibility pressure (MMP) is the threshold for multiple-contact miscibility; measured by slim-tube test for WCSB Midale and Nisku carbonate oils at 12-18 MPa, confirmed before WAG flood design. Water-alternating-gas (WAG) at Weyburn-Midale alternates CO2 and water slugs to improve mobility control and areal sweep; 1:1 WAG at 3-month cycles is the standard WCSB pattern. Carbon capture and storage (CCS) at Quest and ACTL couples industrial CO2 capture with WCSB geological injection; Alberta TIER credits and Clean Fuel Regulations compliance value underpin project economics. Geological carbon storage monitoring at Weyburn and Quest uses annual time-lapse 3D seismic and downhole sensors to verify CO2 containment under AER and Alberta CSTR regulatory frameworks.