copolymer

A copolymer in petroleum chemistry is a polymer molecule formed by the polymerization of two or more chemically distinct monomer units arranged in a defined sequence along the polymer chain, distinguished from a homopolymer (single monomer repeated) by the incorporation of different chemical functionalities at specified positions in the chain that confer properties not achievable with either monomer alone; in Western Canada Sedimentary Basin petroleum operations, copolymers are used across a broad range of applications including enhanced oil recovery (hydrolyzed polyacrylamide-acrylic acid copolymers for polymer flooding at Pelican Lake and Pembina Cardium), drilling fluid rheology and filtration control (AMPS-based synthetic polymer copolymers for high-temperature WBM systems in WCSB Devonian wells), cementing fluid loss additives (AMPS-NVP copolymers for primary cementing at temperatures to 200 degrees Celsius), scale inhibitor chemistry (phosphonate-acrylate copolymers for calcium carbonate and barium sulfate scale control in WCSB produced water systems), and drag reduction agents (ultra-high-molecular-weight polyacrylamide copolymers in WCSB pipeline water injection systems). The most commercially significant WCSB copolymer application is partially hydrolyzed polyacrylamide (HPAM), a copolymer of acrylamide and sodium acrylate monomers at hydrolysis degrees of 25 to 35 mole percent acrylate, which is the workhorse EOR polymer used at Cenovus Pelican Lake (the world's largest polymer flood, northeast Alberta), where HPAM molecular weights of 15 to 22 million Daltons at concentrations of 800 to 2,000 mg/L increase the aqueous phase viscosity from 1 cP (water) to 10 to 80 cP, improving the mobility ratio between the injected polymer slug and the in-place heavy oil (10,000 to 50,000 cP at 12 degrees Celsius reservoir temperature) from an unfavorable value of 10,000 to 50,000 (pure water flooding) to a more favorable value of 125 to 625 (polymer flooding), which dramatically reduces viscous fingering of injected fluid through the heavy oil and improves areal sweep efficiency across the 9,000-hectare Pelican Lake pool. The copolymer architecture of HPAM (acrylamide-acrylate ratio, molecular weight distribution, degree of branching) directly determines its performance in WCSB polymer flooding: higher acrylate content improves salt tolerance (resisting viscosity loss in the 5,000 to 15,000 mg/L total dissolved solids of WCSB Mannville formation water) but increases sensitivity to divalent cations (Ca2+ and Mg2+ above 500 mg/L precipitate HPAM carboxylate groups, causing irreversible polymer degradation that reduces solution viscosity by 50 to 80 percent within days of injection), requiring WCSB Pelican Lake operators to soften injection water below 100 mg/L divalent ions or specify sulfonated polyacrylamide copolymers containing AMPS monomers that resist divalent cation crosslinking.

• HPAM copolymer molecular weight selection and rheological design for WCSB Pelican Lake polymer flooding: The molecular weight of HPAM copolymer used in WCSB polymer flooding determines both the solution viscosity achievable at practical injection concentrations and the injectability of the polymer solution through low-permeability reservoir rock without causing unacceptable injection pressure increase (screen factor) or mechanical degradation of the polymer chains through high-shear pore throats. At Pelican Lake, the Wabiskaw A sand has permeability of 800 to 3,000 mD (unusually high for a heavy oil reservoir), allowing injection of ultra-high-molecular-weight HPAM (18 to 22 million Daltons) at 1,200 to 1,800 mg/L without excessive screen factor (target below 1.2 in a 1.2-micron membrane filter at 25 mL/min test); in lower-permeability WCSB polymer flood candidates (Viking Formation, 50 to 200 mD), HPAM molecular weight must be reduced to 8 to 12 million Daltons to prevent plugging of pore throats below 5 micrometres diameter. Solution viscosity of Pelican Lake HPAM at 1,500 mg/L and 12 degrees Celsius is 30 to 60 cP measured at 7.34 s-1 shear rate (Brookfield viscometer, spindle 18, reservoir shear condition equivalent); dilution and mechanical shearing as the polymer flows from the injection wellbore 200 m into the reservoir reduces in-situ viscosity to 10 to 25 cP at the flood front, still providing a 40 to 100-fold mobility ratio improvement over water flooding of Pelican Lake 20,000 cP heavy oil.
• AMPS-acrylamide copolymer thermal stability and application in WCSB high-temperature drilling and cementing fluids: Conventional HPAM copolymer degrades irreversibly above 70 to 80 degrees Celsius through hydrolysis of the acrylamide groups to acrylate and subsequent calcium salt precipitation; WCSB Devonian wells at 100 to 160 degrees Celsius bottom-hole temperature require thermally stable synthetic copolymers incorporating AMPS (2-acrylamido-2-methylpropanesulfonic acid) monomers whose sulfonate group resists hydrolysis to temperatures above 200 degrees Celsius. AMPS-acrylamide copolymers (25 to 40 mole percent AMPS content) are used in WCSB high-temperature WBM as primary viscosifiers (molecular weight 500,000 to 2,000,000 Daltons, concentration 1 to 3 kg/m3 providing yield point 8 to 18 Pa), displacing xanthan gum and conventional HPAM that would degrade within 24 hours of circulating at Devonian bottom-hole temperatures. AMPS-NVP (N-vinyl-2-pyrrolidone) terpolymers achieve even higher thermal stability (to 230 degrees Celsius) and are the standard fluid loss additive in WCSB high-temperature primary cementing slurries for production casing strings at Devonian Beaverhill Lake and Nisku targets; the NVP monomer provides steric stabilization of the copolymer against thermal uncoiling that reduces filtration performance at high temperature in AMPS-acrylamide binary copolymers above 160 degrees Celsius.
• Phosphonate-acrylate copolymer scale inhibitors for WCSB produced water management: Scale inhibitor copolymers used in WCSB produced water systems combine phosphonate monomers (which adsorb strongly on calcium carbonate and barium sulfate crystal growth sites) with acrylate or maleate monomers (which provide solubility and dispersion in high-salinity WCSB formation water) in a copolymer architecture that achieves minimum inhibitor concentration (MIC) values of 1 to 5 mg/L for calcite and 5 to 20 mg/L for barite scale inhibition, versus 20 to 50 mg/L for simple phosphonate homopolymers. In WCSB Cardium and Devonian produced water systems where calcium concentrations of 500 to 3,000 mg/L and bicarbonate concentrations of 200 to 800 mg/L create calcite supersaturation indices of 1.0 to 2.5 at surface conditions, phosphonate-acrylate copolymer scale inhibitors injected at 5 to 15 mg/L through a downhole capillary tubing string prevent calcite deposition in production tubing and surface equipment without the calcium precipitation problem that limits simple polyacrylate (non-phosphonated) scale inhibitor performance in WCSB high-hardness formation water above 2,000 mg/L calcium. AER Directive 058 requires disclosure of scale inhibitor copolymer chemistry; phosphonate-acrylate copolymers listed as CEPA priority substances require environmental fate data in WCSB produced water disposal well applications.
• Drag-reducing agent copolymers in WCSB water injection and pipeline systems: Ultra-high-molecular-weight polyacrylamide copolymers (molecular weight 10 to 30 million Daltons) are used as drag-reducing agents (DRA) in WCSB water injection pipelines and produced water transfer lines to reduce turbulent friction pressure and increase pipeline throughput without increasing pump power; DRA copolymers work by suppressing turbulent eddies in the boundary layer of flow, reducing the Darcy-Weisbach friction factor by 30 to 70 percent at DRA concentrations of 1 to 10 mg/L. In WCSB Pembina Cardium waterflood programs where surface water injection pipelines operate at flow rates of 3,000 to 8,000 m3/day, DRA addition of 2 to 5 mg/L reduces injection line pressure drop by 40 to 60 percent, allowing a 25 to 40 percent increase in injection rate through the existing pipeline before reaching pump pressure limits; the annual DRA chemical cost of $80,000 to $200,000 is typically offset within 3 to 6 months by the production revenue from increased waterflood injection supporting higher oil production rates. WCSB DRA copolymers are shear-degraded as they pass through pump impellers, reducing their molecular weight and effectiveness, requiring continuous slug injection upstream of each pump stage to maintain the target drag reduction performance along the pipeline.
• Copolymer compatibility and degradation mechanisms in WCSB injection and production environments: Copolymers in WCSB oilfield applications are subject to thermal degradation (chain scission above the thermal stability limit), mechanical degradation (high shear at pump impellers, chokes, and pore throats), chemical degradation (oxidation by dissolved oxygen above 50 ppb, hydrolysis at extreme pH, H2S crosslinking), and biological degradation (enzymatic hydrolysis by sulfate-reducing bacteria where biocide treatment is inadequate). At Pelican Lake, HPAM polymer degradation through oxygen contamination of the injection water was identified as the primary cause of viscosity loss between polymer mixing at surface and polymer arrival at the injection wellbore; dissolved oxygen above 100 ppb reduced HPAM solution viscosity by 30 to 50 percent within 24 hours through free-radical chain scission. Deoxygenation of injection water (vacuum degassing to below 20 ppb O2 or sodium bisulfite scavenging at 0.5 to 1.0 times stoichiometric oxygen content) is now a standard WCSB polymer flood water treatment step that preserves copolymer molecular weight from mixing tank to injection wellbore.

HPAM Copolymer Molecular Weight Optimization Improving Pelican Lake Polymer Flood Performance

Cenovus evaluated two HPAM copolymer grades for a Pelican Lake Wabiskaw A sand pattern: Grade A (18 million Dalton, 30 percent hydrolysis) and Grade B (12 million Dalton, 28 percent hydrolysis), both at 1,500 mg/L in softened injection water (50 mg/L Ca2+). Grade A viscosity at 7.34 s-1 was 55 cP; Grade B was 28 cP. Screen factor for Grade A was 1.14 (passing the 1.2 threshold) and for Grade B was 1.05. Both were injected into a 1,200 mD Wabiskaw A test pattern; injection pressure for Grade A increased by 18 percent above water injection baseline (acceptable), while Grade B increased by 9 percent. After 18 months, the Grade A pattern showed oil rate recovery (reversal of pre-polymer decline) of 35 percent above the pre-injection trend, versus 22 percent for Grade B, attributed to the higher in-situ viscosity of Grade A providing a 2.4-fold lower mobility ratio than Grade B at equal concentration. The incremental oil revenue from the Grade A pattern over 18 months ($1.85 million at $75/bbl WCS) exceeded the incremental polymer cost ($240,000) by a factor of 7.7, confirming Grade A as the preferred copolymer specification for the Pelican Lake expansion program.

Related Terms

Polymer flooding is the primary EOR application of HPAM copolymers in the WCSB; Pelican Lake uses 15 to 22 million Dalton HPAM at 1,200 to 1,800 mg/L to improve mobility ratio from 10,000 (water flood) to 125 to 625 (polymer flood) in 20,000 cP Wabiskaw A heavy oil. Partially hydrolyzed polyacrylamide (HPAM) is the acrylamide-acrylate copolymer used for WCSB EOR polymer flooding; degree of hydrolysis (25 to 35 mole percent acrylate), molecular weight, and salt tolerance determine performance in WCSB Mannville formation water. AMPS (2-acrylamido-2-methylpropanesulfonic acid) is the thermally stable monomer in copolymers for WCSB high-temperature drilling fluid and cementing; AMPS sulfonate groups resist hydrolysis to 200 degrees Celsius, replacing acrylamide-only polymers in Devonian well programs. Scale inhibitor phosphonate-acrylate copolymers prevent calcite and barite deposition in WCSB produced water systems at 1 to 20 mg/L; copolymer architecture achieves lower MIC than simple phosphonate homopolymers in high-hardness WCSB formation water. Drag reduction in WCSB water injection pipelines uses ultra-high-molecular-weight polyacrylamide copolymers at 1 to 10 mg/L to reduce pipeline friction 30 to 70 percent and increase injection throughput by 25 to 40 percent in Pembina Cardium waterflood systems.