Laboratory Support of Heavy-Oil Polymer Flood Project

2016 ◽  
Author(s):  
Rashid S. Al-Maamari ◽  
Abdulaziz Al-Hashmi ◽  
Nasser Al-Azri ◽  
Omaira Al-Riyami ◽  
Rifaat Al-Mjeni ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Polymer Flood

Polymer Flood Design for Displacement of Heavy Oil Analysed by 2D-imaging

2013 ◽  
Author(s):  
A. Skauge ◽  
P.A. Ormehaug ◽  
B.F. Vik ◽  
C. Fabbri ◽  
I. Bondino ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Polymer Flood ◽  
2D Imaging

Polymer Flood Application to Improve Heavy Oil Recovery at East Bodo

2009 ◽  
Vol 48 (02) ◽  
pp. 55-61 ◽  
Author(s):  
F.R. Wassmuth ◽  
K. Green ◽  
W. Arnold ◽  
N. Cameron
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Heavy Oil Recovery ◽  
Polymer Flood

Heavy-Oil Recovery by Combined Hot Water and Alkali/Cosolvent/Polymer Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 74-86 ◽  
Author(s):  
M.. Tagavifar ◽  
R.. Fortenberry ◽  
E.. de Rouffignac ◽  
K.. Sepehrnoori ◽  
G. A. Pope
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Field ◽  
Hot Water ◽  
Mobility Control ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Polymer Flood ◽  
Low Interfacial Tension ◽  
Combined Strategy

Summary A hybrid process is developed and optimized for heavy-oil recovery that combines moderate reservoir heating and chemical enhanced oil recovery in the form of alkali/cosolvent/polymer flood. The process is simulated by use of a model derived from existing laboratory and pilot data of a 5,000-cp heavy-oil field. It is found that hot waterflooding is efficient in heating the reservoir only when high early injectivity is achievable. This may not be the case if incipient fluid injectivity is low and/or long, continuous, horizontal shale baffles are present. To remedy the former, an electrical-preheating period is devised, whereas switching to a horizontal flood could overcome the latter. Once the reservoir temperature is raised sufficiently, a moderately unstable alkali/cosolvent/polymer flood is capable of mobilizing and displacing oil. A best combined strategy for efficient reservoir heating, high oil recovery, and cost effectiveness is found to involve reducing the oil viscosity to values of approximately 300–500 cp and combining a degree of mobility control and low interfacial tension as recovery mechanisms.

scholarly journals Effect of initial water flooding on the performance of polymer flooding for heavy oil production

2020 ◽  
Vol 75 ◽  
pp. 19 ◽  
Author(s):  
Clement Fabbri ◽  
Romain de-Loubens ◽  
Arne Skauge ◽  
Gerald Hamon ◽  
Marcel Bourgeois
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Production ◽  
Water Flooding ◽  
Relative Permeabilities ◽  
Oil Viscosity ◽  
Initial Water ◽  
Polymer Injection ◽  
Polymer Flood

In the domain of heavy to extra heavy oil production, viscous polymer may be injected after water injection (tertiary mode), or as an alternative (secondary mode) to improve the sweep efficiency and increase oil recovery. To prepare field implementation, nine polymer injection experiments in heavy oil have been performed at core scale, to assess key modelling parameters in both situations. Among this consistent set of experiments, two have been performed on reconstituted cylindrical sandpacks in field-like conditions, and seven on consolidated Bentheimer sandstone in laboratory conditions. All experiments target the same oil viscosity, between 2000 cP and 7000 cP, and the viscosity of Partially Hydrolyzed Polyacrylamide solutions (HPAM 3630) ranges from 60 cP to 80 cP. Water and polymer front propagation are studied using X-ray and tracer measurements. The new experimental results presented here for water flood and polymer flood experiments are compared with experiments described in previous papers. The effects of geometry, viscosity ratio, injection sequence on recoveries, and history match parameters are investigated. Relative permeabilities of the water flood experiment are in line with previous experiments in linear geometry. Initial water floods led to recoveries of 15–30% after one Pore Volume Injected (PVI), a variation influenced by boundary conditions, viscosity, and velocities. The secondary polymer flood in consolidated sandstone confirms less stable displacement than tertiary floods in same conditions. Comparison of secondary and tertiary polymer floods history matching parameters suggests two mechanisms. First, hysteresis effect during oil bank mobilization stabilizes the tertiary polymer front; secondly, the propagation of polymer at higher oil saturation leads to lower adsorption during secondary experiment, generating a lower Residual Resistance Factor (RRF), close to unity. Finally, this paper discusses the use of the relative permeabilities and polymer properties estimated using Darcy equation for field simulation, depending on water distribution at polymer injection start-up.

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