chemical flooding

Chemical flooding is an enhanced oil recovery (EOR) method in which chemicals dissolved or dispersed in an aqueous injection fluid are used to improve the displacement efficiency of a waterflood beyond what water alone can achieve, either by reducing the interfacial tension between the injected water and the in-place crude oil (surfactant flooding and alkaline flooding), by increasing the viscosity of the injection fluid to improve the mobility ratio and reduce viscous fingering (polymer flooding), or by combining these mechanisms in a single injection system (alkaline-surfactant-polymer, ASP, flooding) to simultaneously address both capillary trapping and viscous instability as the dominant mechanisms of residual oil entrapment in the swept rock volume; in Western Canada Sedimentary Basin tertiary EOR programs, chemical flooding is the most commercially advanced method applied to light oil (Pembina Cardium and Swan Hills) and heavy oil (Pelican Lake and Taber Mannville) reservoirs where waterflood recovery factors of 25 to 40 percent of original oil in place (OOIP) have been achieved by primary and secondary recovery, leaving 60 to 75 percent of OOIP as residual and bypassed oil that chemical flooding programs target for incremental recovery of an additional 10 to 25 percent OOIP above the waterflood baseline. Polymer flooding in WCSB heavy oil reservoirs is the most commercially proven chemical EOR method in Canada, with Cenovus Energy's Pelican Lake polymer flood (initiated 2006) recovering an estimated 130 to 180 million barrels of incremental oil above the expected waterflood recovery through 2024, making Pelican Lake the world's largest polymer flood by pore volume injected and demonstrating that WCSB heavy oil reservoirs with viscosities of 1,000 to 10,000 cP at reservoir conditions respond strongly to polymer-improved mobility control because the unfavorable mobility ratio between water (1 cP) and heavy oil (1,000 cP) is the dominant recovery-limiting mechanism rather than capillary trapping; surfactant and ASP flooding in WCSB light oil reservoirs remain in pilot stage but have demonstrated incremental recovery factors of 8 to 18 percent OOIP in confined pilot patterns at Pembina Cardium (Cenovus/Penn West ASP pilot, 2009 to 2015) and Lloyd heavy oil (Husky Energy surfactant pilot, 2010 to 2014), confirming the technical applicability of chemical flooding to WCSB reservoirs when crude oil prices justify the incremental chemical cost of $4 to $20 per barrel of incremental oil produced.

• Polymer flooding mechanics and WCSB Pelican Lake Mannville heavy oil application: Polymer flooding improves waterflood sweep efficiency by increasing injection water viscosity through dissolution of a water-soluble polymer (partially hydrolyzed polyacrylamide, HPAM, at 500 to 2,500 mg/L) that raises injection fluid viscosity from 1 cP (water) to 5 to 50 cP, reducing the mobility ratio M = (water mobility) / (oil mobility) from values of 100 to 5,000 in heavy oil waterfloods toward values of 1 to 10 that support stable displacement fronts without viscous fingering. At Pelican Lake in northeast Alberta, the target formation is the Mannville heavy oil reservoir at 340 to 450 m depth with oil viscosity of 1,500 to 8,000 cP at 18 degrees Celsius reservoir temperature and a sand permeability of 1,000 to 5,000 mD; the waterflood mobility ratio was 1,500 to 8,000, meaning the flood front was unstable and water fingered directly through the oil to producing wells within weeks of injection start. HPAM polymer at 900 to 1,800 mg/L (producing a 15 to 40 cP injection viscosity) reduced the effective mobility ratio to 40 to 200, substantially stabilizing the displacement front and increasing areal sweep efficiency from 20 to 30 percent (waterflood estimate) to 50 to 70 percent (polymer flood observed), with Cenovus reporting average polymer flood oil rates 2 to 4 times higher than offset waterflood patterns on comparable Pelican Lake acreage.
• Surfactant flooding mechanism: interfacial tension reduction and residual oil mobilization in WCSB Cardium light oil reservoirs: Surfactant flooding targets capillary-trapped residual oil in the swept pore volume of a waterflood by reducing the interfacial tension (IFT) between the injected aqueous phase and the crude oil from typical waterflood values of 20 to 30 mN/m to ultra-low values of 0.001 to 0.01 mN/m, decreasing the capillary number (Nc = viscous force / capillary force = flood velocity x viscosity / IFT) by a factor of 1,000 to 10,000 above the critical capillary number (10^-5 to 10^-4) at which trapped oil ganglia become mobile and are produced with the injected fluid. In WCSB Pembina Cardium light oil reservoir surfactant flood pilots, internal olefin sulfonate (IOS) surfactants at 0.5 to 2 percent concentration in injection water reduced IFT from 28 mN/m (waterflood) to 0.003 mN/m, mobilizing 12 to 18 percent OOIP additional recovery above waterflood residual oil in confined pattern areas monitored by inter-well tracers; the primary economic challenge of WCSB surfactant flooding is surfactant adsorption onto reservoir rock (Cardium sandstone adsorption of 0.1 to 0.4 mg surfactant per gram of rock), which consumes 20 to 50 percent of injected surfactant before it reaches the targeted oil zone and requires large injection volumes (0.2 to 0.5 pore volumes of surfactant slug) at $2 to $8 per kilogram surfactant cost to achieve commercial incremental recovery.
• Alkaline-surfactant-polymer (ASP) flooding design and WCSB Pembina Cardium pilot results: ASP flooding combines three chemical functions in a single injection system: alkali (sodium carbonate or sodium hydroxide at 0.5 to 2 percent concentration) reacts with naphthenic acids in the crude oil to generate in-situ surfactant at the oil-water interface, reducing alkali consumption and IFT to 0.01 to 0.1 mN/m; co-injected surfactant (0.1 to 0.5 percent, reduced from single-surfactant flood concentration because of alkali synergy) drives IFT to ultra-low values of 0.001 to 0.005 mN/m; and polymer (500 to 1,500 mg/L HPAM) improves the mobility ratio to near-unity, preventing viscous fingering of the ASP slug through the oil zone. The Penn West Petroleum (now Obsidian Energy) Pembina Cardium ASP pilot (2009 to 2015) injected 0.27 pore volumes of ASP slug followed by a polymer drive into a 5-well inverted 5-spot pattern; produced oil incremental recovery above the waterflood baseline was 14 percent OOIP over the pilot period, with the ASP chemical cost of approximately $18 per barrel of incremental oil at 2012 crude prices representing marginal economics at $85 to $95 WTI. Updated economic models at $70 to $80 WTI with improved polymer and surfactant sourcing project ASP break-even at 8 to 12 percent OOIP incremental recovery in WCSB Cardium reservoirs, potentially making full-field ASP economic in high-recovery-factor Cardium pools where waterflood has swept more than 50 percent of OOIP and residual oil saturation is above 15 percent.
• Chemical flood design parameters: slug size, chemical concentration, and injection sequence for WCSB EOR programs: Chemical flood design for WCSB EOR programs follows a standard sequence: a pre-flush stage of fresh water or low-salinity water (0 to 5,000 mg/L TDS) is injected ahead of the chemical slug to condition the reservoir salinity and reduce divalent cation (Ca2+, Mg2+) concentration that would precipitate anionic surfactants or degrade polymer viscosity; the chemical slug (surfactant, polymer, or ASP blend) is injected at 0.1 to 0.5 pore volumes; a polymer drive slug (polymer-only, no surfactant or alkali) at 0.2 to 0.5 pore volumes follows to push the chemical slug deeper into the reservoir and prevent dilution by the chase water; and a chase water stage completes the injection sequence. WCSB reservoir temperature, salinity, and mineralogy constrain chemical selection: Cardium reservoirs at 50 to 65 degrees Celsius and formation water salinity of 20,000 to 80,000 mg/L TDS require thermally stable HPAM grades (sulfonated polyacrylamide for temperatures above 70 degrees Celsius) and internally olefin sulfonate surfactants that maintain ultra-low IFT at formation water salinity rather than freshwater-optimized surfactants that lose performance above 20,000 mg/L.
• Chemical flooding economics and WCSB EOR investment framework under Alberta carbon credit and Enhanced Oil Recovery Royalty Program: Chemical flooding economics in WCSB programs are evaluated on incremental oil produced above the waterflood forecast at a cost per incremental barrel that must be competitive with alternatives including infill drilling, refracking, or miscible flood in the same reservoir. Chemical costs (polymer, surfactant, alkali) represent 40 to 70 percent of total chemical flood operating cost in WCSB programs, with the remainder split between injection facility modifications, chemical handling equipment, and monitoring programs. Alberta's Enhanced Oil Recovery Royalty Program (EORRP) provides a royalty reduction on incremental EOR production above the baseline waterflood forecast, reducing the effective royalty rate on chemical flood incremental oil from the standard 25 to 40 percent to 5 percent for the first 5 years of production, improving project economics by $3 to $8 per barrel of incremental production. The Alberta Carbon Credit Program (TIER) additionally credits chemical flood projects that achieve verified emission intensity reductions below the 2016 baseline through reduced flaring and venting as EOR operations displace less efficient primary production methods, adding $0.50 to $2 per barrel of incremental oil in carbon credit value at 2024 TIER credit prices of $65 per tonne CO2 equivalent.

Pelican Lake Polymer Flood Achieving World-Scale WCSB Heavy Oil EOR Production

Cenovus Energy's Pelican Lake polymer flood in northeast Alberta began commercial injection in 2006 across a 320 km2 area targeting the Mannville heavy oil sand at 340 to 450 m depth with 1,500 to 8,000 cP oil viscosity. HPAM polymer at 900 to 1,800 mg/L was injected through 260 injection wells into a line-drive pattern with 400 m well spacing, reducing the waterflood mobility ratio from 3,000 to 5,000 down to 60 to 150 and stabilizing the displacement front that had previously fingered directly from injectors to producers in 3 to 8 months. By 2015, Pelican Lake polymer flood production was 28,000 barrels per day, more than double the expected waterflood production rate at the same stage; cumulative incremental recovery attributable to the polymer flood above the waterflood baseline exceeded 80 million barrels by 2018 and was projected to reach 130 to 180 million barrels at field abandonment. Chemical cost of HPAM polymer at $2 to $4 per kilogram (delivered to Pelican Lake) resulted in an incremental operating cost of $6 to $12 per barrel of polymer flood incremental oil at 2018 production rates, economically competitive with infill drilling alternatives in the reservoir.

Related Terms

Polymer flooding is the most commercially deployed chemical flooding method in WCSB operations; HPAM polymer improves mobility ratio in heavy oil reservoirs including Pelican Lake and Taber Mannville, where the unfavorable waterflood mobility ratio is the dominant recovery-limiting mechanism. Surfactant is the active chemical component in surfactant and ASP floods; internal olefin sulfonates and other anionic surfactants reduce IFT to ultra-low values that mobilize capillary-trapped residual oil in WCSB Cardium and Viking waterflood-depleted reservoirs. Enhanced oil recovery (EOR) is the category within which chemical flooding falls; chemical flooding is the EOR method most advanced toward commercialization in WCSB light and heavy oil reservoirs, alongside thermal EOR (SAGD, CSS) for oil sands. Mobility ratio is the displacement efficiency parameter that polymer flooding directly controls; reducing the mobility ratio from thousands (heavy oil waterflood) toward unity stabilizes the displacement front and improves WCSB heavy oil recovery factor. Waterflood is the secondary recovery baseline above which chemical flooding delivers incremental recovery; WCSB chemical flood economics are evaluated on the cost per barrel of incremental oil produced above the projected waterflood decline curve at each WCSB pattern location.