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Research Papers: Petroleum Engineering

Micro-Emulsion Phase Behavior of a Cationic Surfactant at Intermediate Interfacial Tension in Sandstone and Carbonate Rocks

[+] Author and Article Information
Mahmood Reza Yassin

Department of Chemical and
Petroleum Engineering,
Sharif University of Technology,
Azadi Street,
P.O. Box 11365-9465,
Tehran, Iran
e-mail: yassin.mahmoodreza@gmail.com

Shahab Ayatollahi

Department of Chemical and
Petroleum Engineering,
Sharif University of Technology,
Azadi Street,
P.O. Box 11365-9465,
Tehran, Iran
e-mail: shahab@sharif.ir

Behzad Rostami

Institute of Petroleum Engineering,
School of Chemical Engineering,
College of Engineering,
University of Tehran,
Karegar Street,
P.O. Box 11365-4563,
Tehran, Iran
e-mail: brostami@ut.ac.ir

Kamran Hassani

Institute of Petroleum Engineering,
School of Chemical Engineering,
College of Engineering,
University of Tehran,
Karegar Street,
P.O. Box 11365-4563,
Tehran, Iran
e-mail: kamranhassani@ut.ac.ir

Vahid Taghikhani

Department of Chemical and
Petroleum Engineering,
Sharif University of Technology,
Azadi Street,
P.O. Box 11365-9465,
Tehran, Iran
e-mail: taghikhani@sharif.edu

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received April 21, 2014; final manuscript received June 15, 2014; published online December 17, 2014. Assoc. Editor: Sarma V. Pisupati.

J. Energy Resour. Technol 137(1), 012905 (Jan 01, 2015) (12 pages) Paper No: JERT-14-1123; doi: 10.1115/1.4029267 History: Received April 21, 2014; Revised June 15, 2014; Online December 17, 2014

Based on the conventional approach, the trapped oil in rock pores can be easily displaced when a Winsor type (III) micro-emulsion is formed in the reservoir during surfactant flooding. On the other hand, the Winsor type (III) involves three phase flow of water, oil, and micro-emulsion that causes considerable oil phase trapping and surfactant retention. This work presents an experimental study on the effect of micro-emulsion phase behavior during surfactant flooding in sandstone and carbonate core samples. In this study, after accomplishing salinity scan of a cationic surfactant (C16–N(CH3)3Br), the effects of Winsor (I), Winsor (III) and Winsor (II) on oil recovery factor, differential pressure drop, relative permeability, and relative permeability ratio were investigated extensively. To carry out a comparative study, homogeneous and similar sandstone and carbonate rocks were selected and the effects of wettability alteration and dynamic surfactant adsorption were studied on them. The results of oil recovery factor in both rock types showed that Winsor (I) and Winsor (III) are preferred compared to Winsor (II) phase behavior. In addition, comparison of normalized relative permeability ratio at high water saturations revealed that Winsor (I) has more appropriate oil and water relative permeability than Winsor (II). The results presented in this paper demonstrate that optimum salinity which results in higher recovery factor and better oil displacement may occur at salinities out of Winsor (III) range. Therefore, the best way to specify optimum salinity is to perform core flood experiments at several salinities, which cover all phase behaviors of Winsor (I), Winsor (III), and Winsor (II).

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Figures

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Fig. 1

Porosity profiles generated by X-ray apparatus

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Fig. 2

Schematic of core flood apparatus

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Fig. 3

Pipette test at 3000 ppm C16-TAB concentration

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Fig. 4

Different types of micro-emulsions and their nomenclatures [11]: low salinity, intermediate salinity, and high salinity

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Fig. 5

Workflow chart for all experiments

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Fig. 6

History matching of oil production data

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Fig. 7

History matching of differential pressure data

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Fig. 8

Recovery factor of sandstone cores at different salinities

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Fig. 9

Differential pressure of sandstone cores at different salinities

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Fig. 10

Micro-emulsion production at Winsor (III) phase behavior

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Fig. 11

Relative permeability of sandstone cores

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Fig. 12

Normalized relative permeability ratio of sandstone cores

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Fig. 13

Recovery factor of carbonate cores at different salinities

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Fig. 14

Differential pressure of carbonate cores at different salinities

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Fig. 15

Relative permeability of carbonate cores

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Fig. 16

Normalized relative permeability ratio of carbonate cores

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Fig. 17

Comparison of recovery factor between sandstone and carbonate tests, Winsor (I), Winsor (II), and Winsor (III)

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Fig. 18

Comparison of relative permeability ratio between sandstone and carbonate tests

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Fig. 19

Effluent fluids at 1.5 pore volumes of injected surfactant: (a) sandstone and (b) carbonate

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Fig. 20

Spontaneous imbibition of surfactant and brine in sandstone core

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Fig. 21

Contact angle of n-heptane drop for carbonate slice before and after soaking in surfactant, CB—oil wet θ = 165 and CB—2 h soaking θ = 62

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