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Design Innovation Papers

Hydrocarbon Recovery From Oil Sands by Cyclic Surfactant Solubilization in Single-Phase Microemulsions

[+] Author and Article Information
Pushpesh Sharma, Sujeewa S. Palayangoda

Department of Petroleum Engineering,
University of Houston,
Houston, TX 77204

Konstantinos Kostarelos

Department of Petroleum Engineering,
University of Houston,
Houston, TX 77204
e-mail: kkostarelos@uh.edu

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received April 16, 2018; final manuscript received January 18, 2019; published online February 14, 2019. Assoc. Editor: Ray (Zhenhua) Rui.

J. Energy Resour. Technol 141(8), 085001 (Feb 14, 2019) (8 pages) Paper No: JERT-18-1275; doi: 10.1115/1.4042715 History: Received April 16, 2018; Revised January 18, 2019

Extra heavy crude oil (bitumen) reserves represent a significant part of the energy resources found all over the world. In Canada, the “oil sands” deposits are typically unconsolidated, water-wet media where current methods of recovery, such as open pit mining, steam-assisted gravity drainage (SAGD), vapor extraction, cold heavy oil production with sand, etc., are controversial due to adverse effect on environment. Chemical enhanced oil recovery (cEOR) techniques have been applied as alternatives but have limited success and contradictory results. An alternative method is described in this paper, which relies on the application of single-phase microemulsion to achieve extremely high solubilization. The produced microemulsion will be less viscous than oil, eliminating the need for solvent addition. Produced microemulsion can be separated to recover surfactant for re-injection. The work in this paper discusses phase behavior experiments and a flow experiment to prove the concept that single-phase microemulsions could be used to recover extra-heavy oils. Phase behavior experiments showed that the mixture of alcohol propoxysulfate, sodium dioctyl sulfosuccinate, sodium carbonate, and tri-ethylene glycol monobutyl ether results in single-phase microemulsion with extra-heavy crude. A flow experiment conducted with the same composition produced only single-phase microemulsion leading to 74% recovery of the original oil in place from a synthetic oil sand. Future experiments will be focused on optimizing the formulation and testing with actual oil sands samples.

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Figures

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Fig. 1

Glass column setup for low-pressure flow experiment conducted at 25 °C. Bottom 6 in. section contains synthetic tar sand.

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Fig. 2

Surfactant screening test tubes for 2 wt % C24–C28 IOS with 4 wt % sec-butanol as co-solvent at 25 °C. This formulation exhibited preferential solubilization detected by GC analysis that would have been undetectable by visual examination alone.

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Fig. 3

Concentration of nine coal tar components in microemulsion measured by GC analysis for 2wt% C24–C28 IOS with 4wt% sec-butanol as co-solvent at 25 °C showing preferential solubilization of components 1, 3, and 4. The nine components are as follows: (1) azulene, (2) 2-methyl naphthalene, (3) acenaphthene, (4) dibenzofuran, (5) fluorene, (6) phenanthrene, (7) fluoranthene, (8) pyrene, and (9) benzopyrene.

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Fig. 4

Surfactant screening test tubes for 4 wt % alcohol propoxy sulfate and 4 wt % sodium dicotyl sulfosuccinate with 4 wt % tri-ethylene glycol monobutyl ether as co-solvent at 25 °C. Upper photograph is under indoor lighting; lower photograph is under UV lighting where the microemulsion is more easily identified.

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Fig. 5

Concentration of nine coal tar components in microemulsion measured by GC analysis for 4wt% alcohol propoxy sulfate and 4wt% sodium dicotyl sulfosuccinate with 4wt% tri-ethylene glycol monobutyl ether as co-solvent at 25 °C analyzed by GC and showing more homogeneous solubilization. The nine components are as follows: (1) azulene, (2) 2-methyl naphthalene, (3) acenaphthene, (4) dibenzofuran, (5) fluorene, (6) phenanthrene, (7) fluoranthene, (8) pyrene, and (9) benzopyrene.

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Fig. 6

Salinity scan for 4 wt % alcohol propoxy sulfate and 4 wt % sodium dicotyl sulfosuccinate with 4 wt % tri-ethylene glycol monobutyl ether as co-solvent and 0.5 wt % sodium carbonate at 25 °C. From top left, four WOR are shown: (a) WOR = 1; (b) WOR = 2; (c) WOR = 3; and (d) WOR = 4.

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Fig. 7

Aqueous stability test for 4 wt % alcohol propoxy sulfate and 4 wt % sodium dicotyl sulfosuccinate with 4 wt % tri-ethylene glycol monobutyl ether as co-solvent and 0.5 wt % sodium carbonate at 25 °C. No phase separation was observed in the pipettes (photograph taken after 1 month).

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Fig. 8

Produced microemulsion from the flow experiment conducted at 25 °C

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Fig. 9

Microemulsion viscosity with PV produced. Viscosity is lower for samples produced that have less solubilized tar.

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Fig. 10

Tar recovery profile for the flow experiment at constant pressure; 50% recovery was achieved with less than 5 PV of surfactant solution injected

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Fig. 11

Concentration profile for tar in produced microemulsion

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Fig. 12

Comparison of sand samples before and after the flow experiment

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