skip to main content
OSTI.GOV title logo U.S. Department of Energy
Office of Scientific and Technical Information

Title: Dilute Surfactant Methods for Carbonate Formations

Abstract

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 formore » anionic surfactants on calcite minerals decreases with increase in pH and with decrease in salinity. Surfactant adsorption can be minimized in the presence of Na{sub 2}CO{sub 3}. 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.« less

Authors:
Publication Date:
Research Org.:
University of Houston
Sponsoring Org.:
USDOE
OSTI Identifier:
882209
DOE Contract Number:
FC26-02NT15322
Resource Type:
Technical Report
Country of Publication:
United States
Language:
English
Subject:
02 PETROLEUM; BRINES; CALCITE; CARBONATES; FRACTURED RESERVOIRS; GAS SATURATION; MOLECULAR WEIGHT; PERMEABILITY; PETROLEUM RESIDUES; SALINITY; SURFACTANTS; TOPOGRAPHY; WATERFLOODING; WETTABILITY

Citation Formats

Kishore K. Mohanty. Dilute Surfactant Methods for Carbonate Formations. United States: N. p., 2006. Web. doi:10.2172/882209.
Kishore K. Mohanty. Dilute Surfactant Methods for Carbonate Formations. United States. doi:10.2172/882209.
Kishore K. Mohanty. Wed . "Dilute Surfactant Methods for Carbonate Formations". United States. doi:10.2172/882209. https://www.osti.gov/servlets/purl/882209.
@article{osti_882209,
title = {Dilute Surfactant Methods for Carbonate Formations},
author = {Kishore K. Mohanty},
abstractNote = {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 Na{sub 2}CO{sub 3}. 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.},
doi = {10.2172/882209},
journal = {},
number = ,
volume = ,
place = {United States},
year = {Wed Feb 01 00:00:00 EST 2006},
month = {Wed Feb 01 00:00:00 EST 2006}
}

Technical Report:

Save / Share:
  • There are many carbonate reservoirs in US (and the world) with light oil and fracture pressure below its minimum miscibility pressure (or reservoir may be naturally fractured). Many carbonate reservoirs are naturally fractured. 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%). Thermal and miscible tertiary recovery techniques are not effective in these reservoirs. Surfactant flooding (or huff-n-puff) is the only hope, yet it was developed for sandstone reservoirs in the past. The goal of this research is to evaluate dilutemore » (hence relatively inexpensive) surfactant methods for carbonate formations and identify conditions under which they can be effective. We have acquired field oil and core samples and field brine compositions from Marathon. We have conducted preliminary adsorption and wettability studies. Addition of Na{sub 2}CO{sub 3} decreases anionic surfactant adsorption on calcite surface. Receding contact angles increase with surfactant adsorption. Plans for the next quarter include conducting adsorption, phase behavior and wettability studies.« less
  • There are many carbonate reservoirs in US (and the world) with light oil and fracture pressure below its minimum miscibility pressure (or reservoir may be naturally fractured). Many carbonate reservoirs are naturally fractured. 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%). Thermal and miscible tertiary recovery techniques are not effective in these reservoirs. Surfactant flooding (or huff-n-puff) is the only hope, yet it was developed for sandstone reservoirs in the past. The goal of this research is to evaluate dilutemore » (hence relatively inexpensive) surfactant methods for carbonate formations and identify conditions under which they can be effective. We have conducted adsorption, phase behavior and wettability studies. Addition of Na{sub 2}CO{sub 3} decreases IFT with a minimum at about 0.2 M. Addition of surfactant decreases IFT further. In the absence of surfactant the minerals are oil wet after aging with crude oil. Addition of surfactant solution decreases the contact angle to intermediate wettability. Addition of Na{sub 2}CO{sub 3} decreases anionic surfactant adsorption on calcite surface. Plans for the next quarter include conducting adsorption, phase behavior and wettability studies.« less
  • There are many carbonate reservoirs in US (and the world) with light oil and fracture pressure below its minimum miscibility pressure (or reservoir may be naturally fractured). Many carbonate reservoirs are naturally fractured. 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%). Thermal and miscible tertiary recovery techniques are not effective in these reservoirs. Surfactant flooding (or huff-n-puff) is the only hope, yet it was developed for sandstone reservoirs in the past. The goal of this research is to evaluate dilutemore » (hence relatively inexpensive) surfactant methods for carbonate formations and identify conditions under which they can be effective. We have conducted adsorption, phase behavior, interfacial tension (IFT) and wettability studies. Addition of Na{sub 2}CO{sub 3} decreases IFT with a minimum at about 0.2 M. Addition of surfactant decreases IFT further. In the absence of surfactant the minerals are oil-wet after aging with crude oil. Addition of surfactant solution decreases the contact angle to intermediate-wet for many surfactants and water-wet for one surfactant. Addition of Na{sub 2}CO{sub 3} decreases anionic surfactant adsorption on calcite surface. Plans for the next quarter include conducting core adsorption, phase behavior, wettability and mobilization studies.« less
  • There are many carbonate reservoirs in US (and the world) with light oil and fracture pressure below its minimum miscibility pressure (or reservoir may be naturally fractured). Many carbonate reservoirs are naturally fractured. 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%). Thermal and miscible tertiary recovery techniques are not effective in these reservoirs. Surfactant flooding (or huff-n-puff) is the only hope, yet it was developed for sandstone reservoirs in the past. The goal of this research is to evaluate dilutemore » (hence relatively inexpensive) surfactant methods for carbonate formations and identify conditions under which they can be effective. We have conducted adsorption, phase behavior, interfacial tension (IFT) and wettability studies. Alfoterra-38 (0.05 wt%), Alfoterra-35 (0.05 wt%), SS-6656 (0.05 wt%), and DTAB (1 wt%) altered the wettability of the initially oil-wet calcite plate to an intermediate/water-wet state. Low IFT ({approx}10{sup -3} dynes/cm) is obtained with surfactants 5-166, Alfoterra-33 and Alfoterra-38. Plans for the next quarter include conducting wettability and mobilization studies.« less
  • There are many carbonate reservoirs in US (and the world) with light oil and fracture pressure below its minimum miscibility pressure (or reservoir may be naturally fractured). Many carbonate reservoirs are naturally fractured. 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%). Thermal and miscible tertiary recovery techniques are not effective in these reservoirs. Surfactant flooding (or huff-n-puff) is the only hope, yet it was developed for sandstone reservoirs in the past. The goal of this research is to evaluate dilutemore » (hence relatively inexpensive) surfactant methods for carbonate formations and identify conditions under which they can be effective. Anionic surfactants (SS-6656, Alfoterra 35, 38, 63,65,68) have been identified which can 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 in the presence of Na{sub 2}CO{sub 3}. All the carbonate surfaces (Lithographic Limestone, Marble, Dolomite and Calcite) show similar behavior with respect to wettability alteration with surfactant 4-22. Anionic surfactants (5-166, Alfoterra-33 and Alfoterra-38 and Alfoterra-68), which lower the interfacial tension with a West Texas crude oil to very low values (<10{sup -2} nM/m), have also been identified. Plans for the next quarter include conducting wettability, mobilization, and imbibition studies.« less