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How Much Polymer Should Be Injected during a Polymer Flood? Review of Previous and Current PracticesNormal access

Author: R.S. Seright
Event name: IOR 2017 - 19th European Symposium on Improved Oil Recovery
Session: Best of Tulsa
Publication date: 24 April 2017
DOI: 10.3997/2214-4609.201700317
Organisations: EAGE
Language: English
Info: Extended abstract, PDF ( 3.77Mb )
Price: € 20

Summary:
This paper provides an extensive review of the polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer flooding field activity. Reasons for the changes are discussed. Even with current floods, a broad range of polymer viscosities are injected—with substantial variations from a base-case design procedure. Extensive discussions with operators and designers of current polymer floods revealed substantial differences of opinion for the optimum design of polymer floods. This paper examines the validity of arguments that are commonly given to justify deviations from the base-case design. For applications involving viscous oils (e.g., 1000 cp), the designed polymer viscosities have sometimes been underestimated because of (1) insufficient water injection while determining relative permeabilities, (2) reliance on mobility ratios at a calculated shock front, and (3) over-estimation of polymer resistance factors and residual resistance factors. In homogeneous reservoirs, the ratio of produced oil value to injected fluid cost is fairly insensitive to injected polymer viscosity (up to the viscosity predicted by the base-case method), especially at low oil prices. However, reservoir heterogeneity and economics of scale associated with the polymer dissolution equipment favor high polymer viscosities over low polymer viscosities, if injectivity is not limiting. Injection above the formation parting pressure and fracture extension are crucial to achieving acceptable injectivity for many polymer floods—especially those using vertical injectors. Under the proper circumstances, this process can increase fluid injectivity, oil productivity, and reservoir sweep efficiency, and also reduce the risk of mechanical degradation for polyacrylamide solutions. The key is to understand the degree of fracture extension for a given set of injection conditions so that fractures do not extend out of the target zone or cause severe channeling. Many field cases exist with no evidence that fractures caused severe polymer channeling or breaching the reservoir seals, in spite of injection above the formation parting pressure. Although at least one case exists (Daqing) where injection of very viscous polymer solutions (i.e., more viscous than the base-case design) reduced Sor below that for waterflooding, our understanding of when and how this occurs is in its infancy. At this point, use of polymers to reduce Sor must be investigated experimentally on a case-by-case basis. A “one-size-fits-all” formula cannot be expected for the optimum bank size. However, experience and technical considerations favor using the largest practical polymer bank. Although graded banks are commonly used or planned in field applications, more work is needed to demonstrate their utility and to identify the most appropriate design procedure.


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