scholarly journals The Role of Microbial Products in Green Enhanced Oil Recovery: Acetone and Butanone

Polymers ◽  
2021 ◽  
Vol 13 (12) ◽  
pp. 1946
Author(s):  
Bashirul Haq
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Process ◽  
Residual Oil ◽  
Core Flooding ◽  
Recovery Potential ◽  
Wide Range ◽  
Green Surfactant ◽  
Core Flood

Green enhanced oil recovery is an oil recovery process involving the injection of specific environmentally friendly fluids (liquid chemicals and gases) that effectively displace oil due to their ability to alter the properties of enhanced oil recovery. In the microbial enhanced oil recovery (MEOR) process, microbes produce products such as surfactants, polymers, ketones, alcohols, and gases. These products reduce interfacial tension and capillary force, increase viscosity and mobility, alter wettability, and boost oil production. The influence of ketones in green surfactant-polymer (SP) formulations is not yet well understood and requires further analysis. The work aims to examine acetone and butanone’s effectiveness in green SP formulations used in a sandstone reservoir. The manuscript consists of both laboratory experiments and simulations. The two microbial ketones examined in this work are acetone and butanone. A spinning drop tensiometer was utilized to determine the interfacial tension (IFT) values for the selected formulations. Viscosity and shear rate across a wide range of temperatures were measured via a Discovery hybrid rheometer. Two core flood experiments were then conducted using sandstone cores at reservoir temperature and pressure. The two formulations selected were an acetone and SP blend and a butanone and SP mixture. These were chosen based on their IFT reduction and viscosity enhancement capabilities for core flooding, both important in assessing a sandstone core’s oil recovery potential. In the first formulation, acetone was mixed with alkyl polyglucoside (APG), a non-ionic green surfactant, and the biopolymer Xanthan gum (XG). This formulation produced 32% tertiary oil in the sandstone core. In addition, the acetone and SP formulation was effective at recovering residual oil from the core. In the second formulation, butanone was blended with APG and XG; the formulation recovered about 25% residual oil from the sandstone core. A modified Eclipse simulator was utilized to simulate the acetone and SP core-flood experiment and examine the effects of surfactant adsorption on oil recovery. The simulated oil recovery curve matched well with the laboratory values. In the sensitivity analysis, it was found that oil recovery decreased as the adsorption values increased.

Ultra-Low Interfacial Tension of a Surfactant under a Wide Range of Temperature and Salinity Conditions for Chemical Enhanced Oil Recovery

2018 ◽  
Vol 55 (3) ◽  
pp. 252-257 ◽  
Author(s):  
Derong Xu ◽  
Wanli Kang ◽  
Liming Zhang ◽  
Jiatong Jiang ◽  
Zhe Li ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Wide Range ◽  
Low Interfacial Tension

Saturated carbon dioxide nanofluids enhanced oil recovery in carbonate reservoir cores using nuclear magnetic resonance

2021 ◽  
Author(s):  
Yongsheng Tan ◽  
Qi Li ◽  
Liang Xu ◽  
Xiaoyan Zhang ◽  
Tao Yu
Keyword(s):  
Carbon Dioxide ◽  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
Core Flooding ◽  
Nuclear Magnetic

<p>The wettability, fingering effect and strong heterogeneity of carbonate reservoirs lead to low oil recovery. However, carbon dioxide (CO<sub>2</sub>) displacement is an effective method to improve oil recovery for carbonate reservoirs. Saturated CO<sub>2</sub> nanofluids combines the advantages of CO<sub>2</sub> and nanofluids, which can change the reservoir wettability and improve the sweep area to achieve the purpose of enhanced oil recovery (EOR), so it is a promising technique in petroleum industry. In this study, comparative experiments of CO<sub>2</sub> flooding and saturated CO<sub>2</sub> nanofluids flooding were carried out in carbonate reservoir cores. The nuclear magnetic resonance (NMR) instrument was used to clarify oil distribution during core flooding processes. For the CO<sub>2</sub> displacement experiment, the results show that viscous fingering and channeling are obvious during CO<sub>2</sub> flooding, the oil is mainly produced from the big pores, and the residual oil is trapped in the small pores. For the saturated CO<sub>2</sub> nanofluids displacement experiment, the results show that saturated CO<sub>2</sub> nanofluids inhibit CO<sub>2</sub> channeling and fingering, the oil is produced from the big pores and small pores, the residual oil is still trapped in the small pores, but the NMR signal intensity of the residual oil is significantly reduced. The final oil recovery of saturated CO<sub>2</sub> nanofluids displacement is higher than that of CO<sub>2</sub> displacement. This study provides a significant reference for EOR in carbonate reservoirs. Meanwhile, it promotes the application of nanofluids in energy exploitation and CO<sub>2</sub> utilization.</p>

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

scholarly journals The Importance of Microemulsion for the Surfactant Injection Process in Enhanced Oil Recovery

2021 ◽  
Author(s):  
Rini Setiati ◽  
Muhammad Taufiq Fathaddin ◽  
Aqlyna Fatahanissa
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Process ◽  
Injection System ◽  
Type I ◽  
Middle Phase ◽  
Interface Tension ◽  
Lower Phase ◽  
Injection Process

Microemulsion is the main parameter that determines the performance of a surfactant injection system. According to Myers, there are four main mechanisms in the enhanced oil recovery (EOR) surfactant injection process, namely interface tension between oil and surfactant, emulsification, decreased interfacial tension and wettability. In the EOR process, the three-phase regions can be classified as type I, upper-phase emulsion, type II, lower-phase emulsion and type III, middle-phase microemulsion. In the middle-phase emulsion, some of the surfactant grains blend with part of the oil phase so that the interfacial tension in the area is reduced. The decrease in interface tension results in the oil being more mobile to produce. Thus, microemulsion is an important parameter in the enhanced oil recovery process.

Enhanced Oil Recovery by Flooding With Dilute Aqueous Chemical Solutions

1981 ◽  
Vol 103 (4) ◽  
pp. 285-290 ◽  
Author(s):  
K. I. Kamath ◽  
S. J. Yan
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Data ◽  
Recovery Process ◽  
Immiscible Displacement ◽  
Residual Oil ◽  
Oil Viscosity ◽  
Recovery Mechanism ◽  
Tertiary Oil Recovery ◽  
Hydrolyzed Polyacrylamide

The theory of enhanced oil recovery by surfactant flooding (micellarpolymer and “low-tension” floods) is based on three premises: that the chemical slug is 1) less mobile than the crude oil, 2) miscible with the reservoir fluids (oil and brine), and 3) stable over long periods of time (years) in the reservoir environment. We report here a rather simple process in which none of these expensive and exacting requirements have to be met. In this process, relatively small amounts of “EOR-active” substances present in certain petroleum-based sulfonates are found to recover 15–20 percent of the residual oil from waterflooded Berea sandstone cores. The chemicals are injected in the form of slugs of their aqueous solutions. If the chemical slugs are followed with similar slugs of additives such as partially hydrolyzed polyacrylamide, acrylamide monomer, urea, EDTA, or anions such as P2O7‴‴‴‴ and PO4‴‴‴, the oil recovery is increased 30–40 percent of the in-place residual oil. The concentrations of the “active” sulfonate and additive in their respective slugs appear to be of the order of 500 ppm or less. Extrapolation of the laboratory data to field conditions indicate that chemical requirements for the recovery of a barrel of tertiary oil are about 0.5–2 lb of sulfonate and a like amount of additive. The main features of the displacement process are: 1) Oil recovery is independent of oil viscosity in the tested range of 0.4–100 cps. 2) The process is essentially an immiscible displacement in which oil recovery depends on the amount of active chemical in the slug and not its concentration. 3) Tertiary oil is produced in the form of a clean “oil bank” and the buildup of a residual oil saturation at the producing end of linear cores occurs during the flood. From the data on hand, it is apparent that the oil recovery mechanism differs basically in character from the conventional Buckley-Leverett-type immiscible displacement. The low level concentrations of sulfonate and additive involved, and the independence of oil recovery with respect to oil viscosity suggest that the recovery mechanism is possibly actuated by certain specific functional groups in the structure of the EOR-active molecule or its anion, and of the additive. The results hold great potential for developing a simple and economical tertiary oil recovery process that can recover, very substantially, more oil (light as well as moderately viscous) than is now considered possible by conventional chemical floods.

scholarly journals Controlled Salinity-Biosurfactant Enhanced Oil Recovery at Ambient and Reservoir Temperatures—An Experimental Study

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1077
Author(s):  
Tinuola Udoh ◽  
Jan Vinogradov
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Core Flooding ◽  
Improved Oil Recovery ◽  
Rock Samples ◽  
Recovery Potential ◽  
System Temperature ◽  
High And Low Temperatures ◽  
First Time ◽  
Increased Oil Recovery

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.

The Effect of Zinc Oxide and Aluminum Oxide Nanoparticles on Interfacial Tension and Viscosity of Nanofluids for Enhanced Oil Recovery

2014 ◽  
Vol 1024 ◽  
pp. 56-59 ◽  
Author(s):  
Hasnah Mohd Zaid ◽  
Noor Rasyada Ahmad Latiff ◽  
Noorhana Yahya
Keyword(s):  
Zinc Oxide ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Substantial Reduction ◽  
Aluminium Oxide ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Aluminum Oxide Nanoparticles

Application of nanotechnology in enhanced oil recovery (EOR) has been increasing in the recent years. After secondary flooding, more than 60% of the original oil in place (OOIP) remains in the reservoir due to trapping of oil in the reservoir rock pores. One of the promising EOR methods is surfactant flooding, where substantial reduction in interfacial tension between oil and water could sufficiently displace oil from reservoir. The emulsion that is created between the two interfaces has a higher viscosity than its original components, providing more force to push the trapped oil. In this paper, the recovery mechanism of the enhanced oil recovery was determined by measuring oil-nanofluid interfacial tension and the viscosity of the nanofluid. Series of core flooding experiments were conducted using packed silica beads whichreplicate core rocks to evaluate the oil recovery efficiency of the nanofluid in comparison to that using an aqueous commercial surfactant, 0.3wt% sodium dodecyl sulfate (SDS). 117 % increase in the recovery of the residual oil in place (ROIP) was observed by the 2 pore volume (PV) injection of aluminium oxide nanofluid in comparison with 0.3wt% SDS. In comparison to the type of material, 5.12% more oil has been recovered by aluminium oxide compared to zinc oxide nanofluid in the presence of EM wave. The effect of the EM wave on the recoverywas also studied by and it was proven that electric field component of the EM waves has been stimulating the nanofluid to be more viscous by the increment of 54.2% in the oil recovery when aluminium oxide nanofluid was subjected to 50MHz EM waves irradiation.

scholarly journals Design and Tuning of Nanofluids Applied to Chemical Enhanced Oil Recovery Based on the Surfactant–Nanoparticle–Brine Interaction: From Laboratory Experiments to Oil Field Application

Nanomaterials ◽  
2020 ◽  
Vol 10 (8) ◽  
pp. 1579 ◽  
Author(s):  
Carlos A. Franco ◽  
Lady J. Giraldo ◽  
Carlos H. Candela ◽  
Karla M. Bernal ◽  
Fabio Villamil ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Field Trial ◽  
Primary Objective ◽  
Field Application ◽  
Ftir Spectra ◽  
Oil Field ◽  
Surfactant Adsorption ◽  
Core Flooding

The primary objective of this study is to develop a novel experimental nanofluid based on surfactant–nanoparticle–brine tuning, subsequently evaluate its performance in the laboratory under reservoir conditions, then upscale the design for a field trial of the nanotechnology-enhanced surfactant injection process. Two different mixtures of commercial anionic surfactants (SA and SB) were characterized by their critical micelle concentration (CMC), density, and Fourier transform infrared (FTIR) spectra. Two types of commercial nanoparticles (CNA and CNB) were utilized, and they were characterized by SBET, FTIR spectra, hydrodynamic mean sizes (dp50), isoelectric points (pHIEP), and functional groups. The evaluation of both surfactant–nanoparticle systems demonstrated that the best performance was obtained with a total dissolved solid (TDS) of 0.75% with the SA surfactant and the CNA nanoparticles. A nanofluid formulation with 100 mg·L−1 of CNA provided suitable interfacial tension (IFT) values between 0.18 and 0.15 mN·m−1 for a surfactant dosage range of 750–1000 mg·L−1. Results obtained from adsorption tests indicated that the surfactant adsorption on the rock would be reduced by at least 40% under static and dynamic conditions due to nanoparticle addition. Moreover, during core flooding tests, it was observed that the recovery factor was increased by 22% for the nanofluid usage in contrast with a 17% increase with only the use of the surfactant. These results are related to the estimated capillary number of 3 × 10−5, 3 × 10−4, and 5 × 10−4 for the brine, the surfactant, and the nanofluid, respectively, as well as to the reduction in the surfactant adsorption on the rock which enhances the efficiency of the process. The field trial application was performed with the same nanofluid formulation in the two different injection patterns of a Colombian oil field and represented the first application worldwide of nanoparticles/nanofluids in enhanced oil recovery (EOR) processes. The cumulative incremental oil production was nearly 30,035 Bbls for both injection patterns by May 19, 2020. The decline rate was estimated through an exponential model to be −0.104 month−1 before the intervention, to −0.016 month−1 after the nanofluid injection. The pilot was designed based on a production increment of 3.5%, which was successfully surpassed with this field test with an increment of 27.3%. This application is the first, worldwide, to demonstrate surfactant flooding assisted by nanotechnology in a chemical enhanced oil recovery (CEOR) process in a low interfacial tension region.

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