Evaluation of ionic effect of green surfactants on interfacial tension reduction under reservoir conditions for enhanced oil recovery

2011 ◽  
Vol 51 (2) ◽  
pp. 727
Author(s):  
Bashirul Haq ◽  
Jishan Liu ◽  
Keyu Liu
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Aquatic Toxicity ◽  
Vital Role ◽  
Bacillus Mojavensis ◽  
Reservoir Condition ◽  
Reservoir Conditions ◽  
Ionic Effects

Ions play a vital role in surfactant chemistry of EOR. The ionic effects of green surfactants are not yet well characterised, but they are biodegradable and environmental friendly, and have great potential for EOR. This study characterises some green anionic and non-ionic surfactants through the determination of the interfacial tension (IFT) of each group and the combined effect of the green surfactants with alcohols on IFT and micro emulsions; and the oil recovery factor through laboratory experiments. Alky Polyglucosides (APG) was selected from the non-ionic group, which can produce ultra low IFT. APG surfactants are produced from coconut/palm oil, corn, potato or wheat residues. Bio-surfactants produced by a microbe called Bacillus mojavensis was taken from the anionic group. This study has found that the APG surfactants are completely and quickly biodegradable and environmentally friendly. APG surfactants show low long-term aquatic toxicity for bacteria, favourable for fish and acceptable effects are on Daphnia and Algae. Our laboratory tests have confirmed that APG PG 8166 can reduce IFT from 12–3.16 dyne/cm at 40 ppm under laboratory ambient condition and from 12–4.32 dyne/cm at a reservoir condition of 50oC and 1000psi. In contrast, the bio-surfactant at 40 ppm decreased IFT from 12–4.14 dyne/cm at the same reservoir condition. Temperature appears to have little effect on the IFT of APG surfactants. There is no significant reduction in the IFT values when APG at 10 ppm combined with the pentanol at concentrations of 15–120 ppm.

Application of Hybrid Biosystems for Stimulation of Oil Production

2021 ◽  
Author(s):  
Baghir Alakbar Suleimanov ◽  
Sabina Jahangir Rzayeva ◽  
Ulviyya Tahir Akhmedova
Keyword(s):  
Oil Recovery ◽  
Single Phase ◽  
Experimental Studies ◽  
Oil Production ◽  
Pore Channel ◽  
Subcritical Region ◽  
Slippage Effect ◽  
Liquid Systems ◽  
Reservoir Conditions

Abstract Microbial enhanced oil recovery is considered to be one of the most promising methods of stimulating formation, contributing to a higher level of oil production from long-term fields. The injection of bioreagents into a reservoir results in the creation of oil-dicing agents along with significant amount of gases, mainly carbon dioxide. In early, the authors failed to study the preparation of self-gasified biosystems and the implementation of the subcritical region (SR) under reservoir conditions. Gasified systems in the subcritical phase have better oil-displacing properties than non-gasified systems. The slippage effect determines the behavior of gas–liquid systems in the SR under reservoir conditions. Slippage occurs more easily when the pore channel has a smaller average radius. Therefore, in a heterogeneous porous medium, the filtration profile of gasified liquids in the SR should be more uniform than for a degassed liquid. The theoretical and practical foundations for the preparation of single-phase self-gasified biosystems and the implementation of the SR under reservoir conditions have been developedSR under reservoir conditions. Based on experimental studies, the superior efficiency of oil displacement by gasified biosystems compared with degassed ones has been demonstrated. The possibility of efficient use of gasified hybrid biopolymer systems has been shown.

Self-gasified biosystems for enhanced oil recovery

2021 ◽  
pp. 2150274
Author(s):  
B. A. Suleimanov ◽  
S. J. Rzayeva ◽  
U. T. Akhmedova
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Experimental Studies ◽  
Microbial Enhanced Oil Recovery ◽  
Heterogeneous Porous Medium ◽  
Oil Displacement ◽  
Subcritical Region ◽  
Reservoir Conditions

Microbial enhanced oil recovery is considered to be one of the most promising methods of stimulating formation, contributing to a higher level of oil production from long-term fields. The injection of bioreagents into a reservoir results in the creation of oil-displacing agents along with a significant amount of gases, mainly carbon dioxide. Earlier, the authors failed to study the preparation of self-gasified biosystems and the implementation of the subcritical region (SR) under reservoir conditions. Gasified systems in the subcritical phase have better oil-displacing properties than nongasified systems. In a heterogeneous porous medium, the filtration profile of gasified liquids in the SR should be more uniform than for a degassed liquid. Based on experimental studies, the superior efficiency of oil displacement by gasified biosystems compared with degassed ones has been demonstrated. The possibility of efficient use of gasified hybrid biopolymer systems has been shown.

scholarly journals Role of Ionic Headgroups on the Thermal, Rheological, and Foaming Properties of Novel Betaine-Based Polyoxyethylene Zwitterionic Surfactants for Enhanced Oil Recovery

Processes ◽  
2019 ◽  
Vol 7 (12) ◽  
pp. 908 ◽  
Author(s):  
Muhammad Shahzad Kamal ◽  
Syed Muhammad Shakil Hussain ◽  
Lionel Talley Fogang
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Oil Recovery ◽  
Structural Changes ◽  
Foam Stability ◽  
Foaming Properties ◽  
Zwitterionic Surfactants ◽  
Reservoir Conditions ◽  
Thermal Stability Of

Long-term thermal stability of surfactants under harsh reservoir conditions is one of the main challenges for surfactant injection. Most of the commercially available surfactants thermally degrade or precipitate when exposed to high-temperature and high-salinity conditions. In this work, we designed and synthesized three novel betaine-based polyoxyethylene zwitterionic surfactants containing different head groups (carboxybetaine, sulfobetaine, and hydroxysulfobetaine) and bearing an unsaturated tail. The impact of the surfactant head group on the long-term thermal stability, foam stability, and surfactant–polymer interactions were examined. The thermal stability of the surfactants was assessed by monitoring the structural changes when exposed at high temperature (90 °C) for three months using 1H-NMR, 13C-NMR, and FTIR analysis. All surfactants were found thermally stable regardless of the headgroup and no structural changes were evidenced. The surfactant–polymer interactions were dominant in deionized water. However, in seawater, the surfactant addition had no effect on the rheological properties. Similarly, changing the headgroup of polyoxyethylene zwitterionic surfactants had no major effect on the foamability and foam stability. The findings of the present study reveal that the betaine-based polyoxyethylene zwitterionic surfactant can be a good choice for enhanced oil recovery application and the nature of the headgroup has no major impact on the thermal, rheological, and foaming properties of the surfactant in typical harsh reservoir conditions (high salinity, high temperature).

scholarly journals Studies on a Foam System of Ultralow Interfacial Tension Applied in Daqing Oilfield after Polymer Flooding

2013 ◽  
Vol 2013 ◽  
pp. 1-6 ◽  
Author(s):  
Hong-sheng Liu ◽  
Jing-qin Wang ◽  
Li Yang ◽  
Dong-yang Jiang ◽  
Chang-sen Lv ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Surfactant Concentration ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Reservoir Conditions ◽  
Foam Properties ◽  
Injection Methods ◽  
Ultralow Interfacial Tension ◽  
Flow Experiments

In order to study the effects of oil displacement by a foam system of ultralow interfacial tension, the interfacial activities and foam properties of a nonionic gemini surfactant (DWS) were investigated under Daqing Oilfield reservoir conditions. Injection methods and alternate cycle of the foam system were discussed here on the basis of results from core flow experiments. It was obtained that the surface tension of DWS was approximately 25 mN/m, and ultralow interfacial tension was reached between oil and DWS with a surfactant concentration between 0.05wt% and 0.4wt%. The binary system showed splendid foam performances, and the preferential surfactant concentration was 0.3wt% with a polymer concentration of 0.2wt%. When gas and liquid were injected simultaneously, flow control capability of the foam reached its peak at the gas-liquid ratio of 3 : 1. Enhanced oil recovery factor of the binary foam system exceeded 10% in a parallel natural cores displacement after polymer flooding.

scholarly journals Experimental Determination of CO2 Diffusion Coefficient in a Brine-Saturated Core Simulating Reservoir Condition

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 540
Author(s):  
Zerong Li ◽  
Lei Yuan ◽  
Guodong Sun ◽  
Junchen Lv ◽  
Yi Zhang
Keyword(s):  
Diffusion Coefficient ◽  
Co2 Storage ◽  
Co2 Diffusion ◽  
Nacl Concentration ◽  
Reservoir Conditions ◽  
Temperature And Pressure ◽  
The Relationship ◽  
Crucial Part

CO2 diffusion coefficient plays a crucial part in saline aquifers for the CO2 storage and the safety of long-term sequestration. Therefore, it is particularly important to measure the diffusion coefficient accurately. As far as we know, there are currently no CO2 brine diffusion data in real cores under reservoir temperature and pressure conditions. In this paper, a study on the CO2 diffusion coefficient diffused in a brine-saturated Berea core along the radial direction was conducted at temperatures of 313.15 K to 373.15 K and pressures of 8 MPa to 30 MPa. On account of the experimental results, the effect of permeability, NaCl concentration, temperature and pressure on the CO2 diffusivity is analyzed. The results in this study indicate that the diffusion coefficient increases with increasing permeability, pressure and temperature and decreases with increasing NaCl concentration. However, the relationship between pressure and the diffusion coefficient is not linear. As the pressure gradually increases, the effect of pressure will become weak. In addition, an empirical correlation of the relationship between temperature–pressure and the CO2 diffusion coefficient could be obtained based on the experimental data. The data in this paper fill the blank on the study of the CO2 diffusivity in brine under reservoir conditions, which has positive significance for the study of supercritical CO2 diffusion in a brine-saturated core.

scholarly journals Quick, Easy and Economic Mineralogical Studies of Flooded Chalk for EOR Experiments Using Raman Spectroscopy

2018 ◽  
Author(s):  
Laura Borromeo ◽  
Nina Egeland ◽  
Mona Wetrhus Minde ◽  
Udo Zimmermann ◽  
Sergio Andò ◽  
...  
Keyword(s):  
Raman Spectroscopy ◽  
Effective Stress ◽  
Oil Recovery ◽  
Secondary Growth ◽  
Mineral Dissolution ◽  
Petroleum Exploration ◽  
Reservoir Conditions ◽  
Electron Microscopes ◽  
Non Destructive

Understanding the chalk-fluid interactions and the associated mineralogical and mechanical alteration at sub-micron scale are major goals in Enhanced Oil Recovery. Mechanical strength, porosity, and permeability of chalk are linked to mineral dissolution that occurs during brine injections, and affect the reservoir potential. This paper presents a novel "single grain" methodology to recognize the varieties of carbonates in rocks and loose sediments: Raman spectroscopy is a non-destructive, quick, and user-friendly technique representing a powerful tool to identify minerals down to 1 µm. An innovative working technique for oil exploration is proposed, as the mineralogy of micron-sized crystals grown in two flooded chalk samples (Liége, Belgium) was successfully investigated by Raman spectroscopy. The drilled chalk cores were flooded with MgCl2 for c. 1.5 (Long Term Test) and 3 years (Ultra Long Term Test) under North Sea reservoir conditions (Long Term Test: 130°C, 1 PV/day, 9.3 MPa effective stress; Ultra Long Term Test: 130°C, varying between 1-3 PV/day, 10.4 MPa effective stress). Raman spectroscopy was able to identify the presence of recrystallized magnesite along the core of the Long Term Test up to 4 cm from the injection surface, down to the crystal size of 1-2 µm. In the Ultra Long Term Test core the growth of MgCO3 affected nearly the entire core (7 cm). In both samples, no dolomite or high-magnesium calcite secondary growth could be detected when analysing 557 and 90 Raman spectra on the Long and Ultra Long Term Test, respectively. This study can offer Raman spectroscopy as a breakthrough tool in petroleum exploration of unconventional reservoirs, due to its quickness, spatial resolution, and non-destructive acquisition of data. These characteristics would encourage its use coupled with electron microscopes and energy dispersive systems or even electron microprobe studies.

Computational Modeling of the Influence of Geminal Zwitterionic Liquids on Changes in the Parameters of Wetting of Oil-Rock System

2012 ◽  
Vol 1473 ◽  
Author(s):  
Ernesto Lopez-Chavez ◽  
Luis Silvestre Zamudio-Rivera ◽  
Jose Manuel Martinez-Magadan ◽  
Eduardo Buenrostro-Gonzalez ◽  
Raúl Hernández-Altamirano
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Theoretical Study ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Rock System ◽  
Reservoir Conditions ◽  
Low Interfacial Tension ◽  
Limestone Rock

ABSTRACTZwitterionic liquid (ZL) molecules are considered among the surfactant molecular species used in enhanced oil recovery (EOR). The surface activity of asphaltenes (ASP) is crucial for establishing reservoir rock wettability, which impacts enhanced oil recovery (EOR) process. The key to a successful EOR formulation is to carefully select the components that provide ultra-low interfacial tension (IFT) under reservoir conditions. Achieving ultra-low IFT greatly reduces capillary forces that trap oil. The objective of this work is the theoretical study of the influence of a class of germinal zwitterionic liquid on interfacial tension or changes on wettability of the oil-rock system under reservoir conditions. The ZL molecule used in this study was designed by Zamudio et al; while the asphaltene model was originally proposed by Buenrostro-González. Methods of molecular mechanics and dynamics were used in order to calculate interaction energies of all systems. The results indicate that the ZL molecule adheres more strongly to the limestone-rock than the asphaltene molecule does. In addition, our results suggest that the ion-pair formation is the dominant wettability alteration mechanism.

The effects of reservoir brine compositions on interfacial tension and reservoir wettability under reservoir conditions

2010 ◽  
Vol 50 (2) ◽  
pp. 735
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Fluid Distribution ◽  
Residual Water ◽  
Reservoir Properties ◽  
Diverse Range ◽  
Reservoir Conditions ◽  
Original Oil In Place ◽  
Increasing Temperature

The average primary oil recovery worldwide is around 35% of the original oil in place (OOIP). Various enhanced oil recovery (EOR) approaches are generally required to recover the remaining OOIP. Apart from the reservoir properties, the capillary pressure that governs fluid distribution and displacement behavior in the reservoir is also affected by the interfacial tension and wettability. Both IFT and wettability are considered to be key effective factors that affect EOR. This study investigated the effect of reservoir brine compositions on the interfacial tension (IFT) between synthetic formation brines and an Australian crude oil with pressures and temperatures up to 4000 psi and 140 °F, respectively. A series of measurements on the density, viscosity and IFT have been conducted. The brines, with total dissolved solids ranging from 3,820 to 38,200 ppm, consist of a diverse range of ions including sodium, lithium, magnesium, calcium, bromide, chloride, sulfate, bicarbonate and carbonate. The experimental results indicate that with all the synthetic brines investigated, the IFT declines with increasing temperature and pressure. Furthermore, it was observed that the IFT reduction with temperature was dependent on the pH values of the brine. Bicarbonate, carbonate, sulfate, and magnesium ions significantly decreased the IFT by up to 40% through either lowering the free surface energy or increasing the surface area. Coreflooding experiments using low salinity water have yielded an incremental EOR of 5.4% OOIP, suggesting that wettability alteration caused by the change of ion balance in the residual water may be responsible for the observed EOR.

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