Actions for Dilute Surfactant Methods for Carbonate Formations [electronic resource].

Email RIS file
Bookmark
Report an Issue

Dilute Surfactant Methods for Carbonate Formations [electronic resource].

Published
Washington, D.C. : United States. Dept. of Energy, 2006.
Oak Ridge, Tenn. : Distributed by the Office of Scientific and Technical Information, U.S. Dept. of Energy.
Additional Creators
University of Houston, United States. Department of Energy, and United States. Department of Energy. Office of Scientific and Technical Information
Access Online

Availability

I Want It
I Want It

Finding items...

Restrictions on Access
Free-to-read Unrestricted online access
Summary
There are many fractured carbonate reservoirs in US (and the world) with light oil. Waterflooding is effective in fractured reservoirs, if the formation is water-wet. Many fractured carbonate reservoirs, however, are mixed-wet and recoveries with conventional methods are low (less than 10%). The process of using dilute anionic surfactants in alkaline solutions has been investigated in this work for oil recovery from fractured oil-wet carbonate reservoirs both experimentally and numerically. This process is a surfactant-aided gravity drainage where surfactant diffuses into the matrix, lowers IFT and contact angle, which decrease capillary pressure and increase oil relative permeability enabling gravity to drain the oil up. Anionic surfactants have been identified which at dilute concentration of 0.05 wt% and optimal salinity can lower the interfacial tension and change the wettability of the calcite surface to intermediate/water-wet condition as well or better than the cationic surfactant DTAB with a West Texas crude oil. The force of adhesion in AFM of oil-wet regions changes after anionic surfactant treatment to values similar to those of water-wet regions. The AFM topography images showed that the oil-wetting material was removed from the surface by the anionic surfactant treatment. Adsorption studies indicate that the extent of adsorption for anionic surfactants on calcite minerals decreases with increase in pH and with decrease in salinity. Surfactant adsorption can be minimized in the presence of Na₂CO₃. Laboratory-scale surfactant brine imbibition experiments give high oil recovery (20-42% OOIP in 50 days; up to 60% in 200 days) for initially oil-wet cores through wettability alteration and IFT reduction. Small (<10%) initial gas saturation does not affect significantly the rate of oil recovery in the imbibition process, but larger gas saturation decreases the oil recovery rate. As the core permeability decreases, the rate of oil recovery reduces, and this reduction can be scaled by the gravitational dimensionless time. Mechanistic simulation of core-scale surfactant brine imbibition matches the experimentally observed imbibition data. In-situ distributions observed through simulation indicate that surfactant diffusion (which depends on temperature and molecular weight) is the rate limiting step. Most of the oil is recovered through gravitational forces. Oil left behind at the end of this process is at its residual oil saturation. The capillary and Bond numbers are not large enough to affect the residual oil saturation. At the field-scale, 50% of the recoverable oil is produced in about 3 years if the fracture spacing is 1 m and 25% if 10 m, in the example simulated. Decreasing fracture spacing and height, increasing permeability, and increasing the extent of wettability alteration increase the rate of oil recovery from surfactant-aided gravity drainage. This dilute surfactant aided gravity-drainage process is relatively cheap. The chemical cost for a barrel of oil produced is expected to be less than $1.
Report Numbers
E 1.99:882209
Subject(s)
Other Subject(s)
Note
Published through SciTech Connect.
02/01/2006.
Kishore K. Mohanty.
Type of Report and Period Covered Note
Final;
Funding Information
FC26-02NT15322
View MARC record | catkey: 14702888