Controlled salinity-biosurfactant enhanced oil recovery at ambient and reservoir temperatures: an experimental study

Tinuola Udoh; Jan Vinogradov

doi:10.3390/en14041077

Controlled salinity-biosurfactant enhanced oil recovery at ambient and reservoir temperatures: an experimental study

Tinuola Udoh, Jan Vinogradov^* (Corresponding Author)

^*Corresponding author for this work

Engineering

Research output: Contribution to journal › Article › peer-review

4 Citations (Scopus)

2 Downloads (Pure)

Abstract

In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme® and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relative
to injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 ° C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs.

Original language	English
Article number	1077
Number of pages	19
Journal	Energies
Volume	14
Issue number	4
DOIs	https://doi.org/10.3390/en14041077
Publication status	Published - 16 Feb 2021

Bibliographical note

Funding: This research was funded by Tertiary Education Trust Fund (TETFund) grant through Akwa Ibom State University staff development scheme.
Acknowledgments: The assistance of Lateef Akanji and Abb ie Mclaughlin of the University of Aberdeen is highly appreciated. We also appreciate Biotech Processing Supply (Dallas, TX, USA) for the supply of GreenZyme® used in this study. Finally, the financial support of Tertiary Education Trust Fund (TETFund) through Akwa Ibom State University is highly appreciated

Keywords

Controlled salinity waterflooding
controlled salinity-biosurfactant EOR
EOR
reservoir conditions
controlled salinity waterflooding

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Cite this

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title = "Controlled salinity-biosurfactant enhanced oil recovery at ambient and reservoir temperatures: an experimental study",

abstract = " In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme{\textregistered} and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relativeto injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 ° C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs. ",

keywords = "Controlled salinity waterflooding, controlled salinity-biosurfactant EOR, EOR, reservoir conditions, controlled salinity waterflooding",

author = "Tinuola Udoh and Jan Vinogradov",

note = "Funding: This research was funded by Tertiary Education Trust Fund (TETFund) grant through Akwa Ibom State University staff development scheme. Acknowledgments: The assistance of Lateef Akanji and Abb ie Mclaughlin of the University of Aberdeen is highly appreciated. We also appreciate Biotech Processing Supply (Dallas, TX, USA) for the supply of GreenZyme{\textregistered} used in this study. Finally, the financial support of Tertiary Education Trust Fund (TETFund) through Akwa Ibom State University is highly appreciated",

year = "2021",

month = feb,

day = "16",

doi = "10.3390/en14041077",

language = "English",

volume = "14",

journal = "Energies",

issn = "1996-1073",

publisher = "MDPI",

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T1 - Controlled salinity-biosurfactant enhanced oil recovery at ambient and reservoir temperatures

T2 - an experimental study

AU - Udoh, Tinuola

AU - Vinogradov, Jan

N1 - Funding: This research was funded by Tertiary Education Trust Fund (TETFund) grant through Akwa Ibom State University staff development scheme. Acknowledgments: The assistance of Lateef Akanji and Abb ie Mclaughlin of the University of Aberdeen is highly appreciated. We also appreciate Biotech Processing Supply (Dallas, TX, USA) for the supply of GreenZyme® used in this study. Finally, the financial support of Tertiary Education Trust Fund (TETFund) through Akwa Ibom State University is highly appreciated

PY - 2021/2/16

Y1 - 2021/2/16

N2 - In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme® and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relativeto injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 ° C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs.

AB - In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme® and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relativeto injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 ° C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs.

KW - Controlled salinity waterflooding

KW - controlled salinity-biosurfactant EOR

KW - EOR

KW - reservoir conditions

KW - controlled salinity waterflooding

U2 - 10.3390/en14041077

DO - 10.3390/en14041077

M3 - Article

SN - 1996-1073

VL - 14

JO - Energies

JF - Energies

IS - 4

M1 - 1077

ER -

Controlled salinity-biosurfactant enhanced oil recovery at ambient and reservoir temperatures: an experimental study

Abstract

Bibliographical note

Keywords

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