How Much Polymer Should Be Injected During a Polymer Flood? Review of Previous and Current Practices

R.S Seright – 2017

Abstract

This paper provides an extensive review of polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods, covering the past 50 years. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer flooding. The paper examines the validity of arguments commonly given to justify low polymer viscosities. For viscous oils (1,000 cp), designed polymer viscosities have sometimes been underestimated due to insufficient water injection while determining relative permeabilities, reliance on mobility ratios at the shock front, and overestimation of resistance factors. In homogeneous reservoirs, the ratio of produced-oil value to injected-fluid cost is fairly insensitive to polymer viscosity up to the base-case optimum. Reservoir heterogeneity and dissolution-equipment economics favor high polymer viscosities if injectivity is not limiting. Injection above the formation-parting pressure and fracture extension are crucial for acceptable injectivity in many floods. Experience and technical considerations favor the largest practical polymer bank.

Key Takeaways

  • Polymer flood designs in the past 25 years use substantially higher polymer concentrations, viscosities, and bank sizes than the first 30 years of polymer flooding activity — reflecting accumulated knowledge that larger, more viscous slugs perform better.
  • For viscous oils (1,000 cp), designed polymer viscosities are often underestimated because of: insufficient water injection during relative permeability measurement, over-reliance on shock-front mobility ratios, and overestimation of in-reservoir resistance factors.
  • In homogeneous reservoirs, the ratio of oil value to polymer injection cost is largely insensitive to polymer viscosity up to the base-case optimum — there is no economic penalty for using higher viscosity up to that threshold.
  • Injection above the formation-parting pressure and controlled fracture extension are crucial for acceptable injectivity in many polymer floods, especially with vertical injectors — multiple field cases confirm no severe channeling when fractures are properly managed.
  • Experience favors the largest practical polymer bank size — a ‘one-size-fits-all’ optimal bank does not exist, but technical and economic considerations consistently point toward larger rather than smaller slugs.
Read Article

Related Articles