Synergistic Effects of Engineered Water-Nanoparticle on Oil/Brine/Rock Interactions in Carbonates

2021 ◽  
Author(s):  
Ibraheem Salaudeen ◽  
Muhammad Rehan Hashmet ◽  
Peyman Pourafshary
Keyword(s):  
Contact Angle ◽  
Zeta Potential ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Sea Water ◽  
Hybrid Methods ◽  
Carbonate Reservoir ◽  
Wettability Alteration ◽  
Combined Effects ◽  
Low Salinity

Abstract Nano particle-assisted engineered water is one of the newest hybrid methods of Enhanced Oil Recovery (EOR) that is gaining attention in the oil and gas industry. This is attributed to the low cost of the technique and environmental friendliness of the materials involved. Low salinity and ions adjustment of the injection brine has been reported to be very useful for improving oil production in carbonates, and application of nanoparticles (NPs) to improve oil recovery via different mechanisms such as wettability alteration, interfacial tension reduction, disjoining pressure and viscosity modification. This paper therefore investigates the combined effects of these two techniques on oil-brine-rock (OBR) interactions in carbonate reservoirs. Caspian Sea Water salinity of 13000 ppm was synthesized in the laboratory, potential determining ions such as Mg2+, Ca2+ and SO42- were adjusted to obtain the desired engineered waters used as dispersant for SiO2 nanoparticle. A series of experiments were performed ranging from zeta potential, interfacial tension, contact angle, electron scanning environmental imaging, pH analysis and particle size to determine the optimum formulation of engineered low salinity brine and nanoparticle. The salinities and concentration of NP considered in this experimental study ranges between (3,250 - 40,000) ppm and (0.05 - 0.5) wt.%, respectively. It was observed that optimum homogenization time for achieving stability of the chosen nanofluid without using stabilizer is 45 minutes. Four times sulphate and calcium ions in the engineered water reduced the contact angle from 163 to 109 and 151 to 118 degrees respectively. However, in the presence of NP, the contact angle further reduced to a very low values of 5 and 41 degrees. This confirms the combined effects of EW and that of nanofluid (NF) in altering wettability from the hydrophobicity state to hydrophilicity one that rapidly improves oil recovery in carbonate reservoir. IFT measurements were made between oil and formation brine as well as between oil and different EWs at room temperature. The Formation water has the least value of interfacial tension- 15mN/m. Four times diluted sea water spiked with four times sulphate is denoted as 4dsw4S. The zeta potential values showed dsw4S-NF to be the most stable, whereas EW-NF spiked with 4 times Mg2+ show detrimental effects on NF stability. The nanoparticles sizes were measured to be less than 50 nm. Rheological studies of the EW-NF at different temperatures (25, 40, 60 and 80 degrees Celsius) shows similar trend of Newtonian and non-Newtonian behavior at shear rate less than 100 and above 100 per seconds respectively. We conclude that spiking calcium ion and sulphate ion into the injected brine in combination with 0.1wt% NP yielded the wettability alteration in carbonate rock samples. The significant reduction in wettability is attributed to the combined effects of the active mechanisms present in the hybrid method and is considerably better than each standalone technique.

Wettability Alteration During Low-Salinity Waterflooding in a Deep Tight Carbonate Reservoirs: A Quantitative and Visual Investigation Through Spontaneous Imbibition and Zeta Potentiometric Studies

2021 ◽  
Author(s):  
N. Singh ◽  
P. H. Gopani ◽  
H. K. Sarma ◽  
F. Wu ◽  
P. S. Mattey ◽  
...  
Keyword(s):  
Contact Angle ◽  
Zeta Potential ◽  
Carbonate Reservoir ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Rock Interaction ◽  
Low Salinity ◽  
Tight Carbonate ◽  
Repulsive Forces

Abstract This study focusses on the investigation of wettability alteration behavior during low salinity waterflood (LSWF) process in a tight carbonate reservoir through Zeta potential studies in conjunction with spontaneous imbibition tests and estimation of the contact angle between the wetting fluid and the rock surface. This will help in understanding the role rock-oil-brine interactions play during an LSWF process. The classical streaming potential technique were used to determine Zeta potential. Measurements were carried out with diluted brines using different rock samples of in two states: oil-saturated and brine-saturated. The experimental results imply that the value of zeta potential becomes more negative with increasing percentage of dilution (25%, 10%, and 1%). This is attributed to electrical double-layer expansion which is caused, primarily, by the reduced ionic strength. We concluded that rock saturated with oil may give an insight on oil rock interactions while the rock saturated with brine may give insight on rock-brine interactions. The dilution of water helps increase the electrostatic repulsive forces between the two interfaces, which in turns, leads to the incremental recovery during LSWF process. This observation was also confirmed by coreflooding and wettability experiments through spontaneous imbibition tests and contact angle measurements conducted using the same oil-brine-rock systems. This is an investigative study of oil-brine-rock interaction behavior during a LSWF process that is difficult to accomplish through and during a conventional coreflooding displacement test. In addition, this study also couples the relationship between the wettability alteration and oil-brine-rock interactions during an LSWF process.

scholarly journals Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

2021 ◽  
Author(s):  
Xu-Guang Song ◽  
Ming-Wei Zhao ◽  
Cai-Li Dai ◽  
Xin-Ke Wang ◽  
Wen-Jiao Lv
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Liquid Interface ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Low Permeability ◽  
Oil Water ◽  
Solid Liquid

AbstractThe ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention. In this work, the active silica nanofluids were prepared by modified active silica nanoparticles and surfactant BSSB-12. The dispersion stability tests showed that the hydraulic radius of nanofluids was 58.59 nm and the zeta potential was − 48.39 mV. The active nanofluids can simultaneously regulate liquid–liquid interface and solid–liquid interface. The nanofluids can reduce the oil/water interfacial tension (IFT) from 23.5 to 6.7 mN/m, and the oil/water/solid contact angle was altered from 42° to 145°. The spontaneous imbibition tests showed that the oil recovery of 0.1 wt% active nanofluids was 20.5% and 8.5% higher than that of 3 wt% NaCl solution and 0.1 wt% BSSB-12 solution. Finally, the effects of nanofluids on dynamic contact angle, dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofluids at solid–liquid and liquid–liquid interface. The oil detaching and transporting are completed by synergistic effect of wettability alteration and interfacial tension reduction. The findings of this study can help in better understanding of active nanofluids for EOR in ultra-low permeability reservoirs.

scholarly journals A Core Flood and Microfluidics Investigation of Nanocellulose as a Chemical Additive to Water Flooding for EOR

Nanomaterials ◽  
2020 ◽  
Vol 10 (7) ◽  
pp. 1296 ◽  
Author(s):  
Reidun C. Aadland ◽  
Salem Akarri ◽  
Ellinor B. Heggset ◽  
Kristin Syverud ◽  
Ole Torsæter
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Cellulose Nanofibrils ◽  
Water Flooding ◽  
Low Salinity ◽  
The Core ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Flood

Cellulose nanocrystals (CNCs) and 2,2,6,6-tetramethylpiperidine-1-oxyl (TEMPO)-oxidized cellulose nanofibrils (T-CNFs) were tested as enhanced oil recovery (EOR) agents through core floods and microfluidic experiments. Both particles were mixed with low salinity water (LSW). The core floods were grouped into three parts based on the research objectives. In Part 1, secondary core flood using CNCs was compared to regular water flooding at fixed conditions, by reusing the same core plug to maintain the same pore structure. CNCs produced 5.8% of original oil in place (OOIP) more oil than LSW. For Part 2, the effect of injection scheme, temperature, and rock wettability was investigated using CNCs. The same trend was observed for the secondary floods, with CNCs performing better than their parallel experiment using LSW. Furthermore, the particles seemed to perform better under mixed-wet conditions. Additional oil (2.9–15.7% of OOIP) was produced when CNCs were injected as a tertiary EOR agent, with more incremental oil produced at high temperature. In the final part, the effect of particle type was studied. T-CNFs produced significantly more oil compared to CNCs. However, the injection of T-CNF particles resulted in a steep increase in pressure, which never stabilized. Furthermore, a filter cake was observed at the core face after the experiment was completed. Microfluidic experiments showed that both T-CNF and CNC nanofluids led to a better sweep efficiency compared to low salinity water flooding. T-CNF particles showed the ability to enhance the oil recovery by breaking up events and reducing the trapping efficiency of the porous medium. A higher flow rate resulted in lower oil recovery factors and higher remaining oil connectivity. Contact angle and interfacial tension measurements were conducted to understand the oil recovery mechanisms. CNCs altered the interfacial tension the most, while T-CNFs had the largest effect on the contact angle. However, the changes were not significant enough for them to be considered primary EOR mechanisms.

scholarly journals Sandstone Reservoir Wettability Alteration Due to Water Softening: Impact of Silica Nanoparticles on Sand Production Mechanism

2020 ◽  
Vol 10 (5) ◽  
pp. 6328-6342 ◽  
Keyword(s):  
Contact Angle ◽  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Sand Production ◽  
Thin Sections ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Low salinity water in the oil reservoirs changes the wettability and increases the oil recovery factor. In sandstone reservoirs, the sand production occurs or intensifies with wettability alteration due to low salinity water injection. In any case, sand production should be stopped and there are many ways to prevent sand production. By modifying the composition of low salinity water, it can be adapted to be more compatible with the reservoir rock and formation water, which has the least formation damage. By eliminating magnesium and calcium ions, smart soft water (SSW) is created which is economically suitable for injection into the reservoirs. By stabilizing the nanoparticles in SSW, nanofluids can be prepared which with injection into the sandstones reservoir increase the oil recovery, change the wettability and increase the rock strength. In this present, SSW composition was determined by compatibility testing, and the SiO2 nanoparticle with 1000 ppm concentration was stabilized in SSW. Eight thin sections were oil wetted by using normal heptane solution and different molars of stearic acid and two thin sections were considered as base thin sections to compare the effect of wettability alteration on sand production. Thin sections were immersed in SSW and Nanofluid, the amount of contact angle and sand production were measured in both cases. The amount of sand produced and the contact angle in SSW was higher than the Nanofluid. The silica nanoparticles reduced the contact angle (more water wetting) and by sitting between the sand particles, more than 40%, it reduced sand production.

scholarly journals A Review on the Progress of Ion-Engineered Water Flooding

2017 ◽  
Vol 2017 ◽  
pp. 1-9 ◽  
Author(s):  
Alibi Kilybay ◽  
Bisweswar Ghosh ◽  
Nithin Chacko Thomas
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Water Injection ◽  
Oil And Gas Industry ◽  
Carbonate Reservoir ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Gas Industry ◽  
Low Salinity ◽  
Smart Water

In the oil and gas industry, Enhanced Oil Recovery (EOR) plays a major role to meet the global requirement for energy. Many types of EOR are being applied depending on the formations, fluid types, and the condition of the field. One of the latest and promising EOR techniques is application of ion-engineered water, also known as low salinity or smart water flooding. This EOR technique has been studied by researchers for different types of rocks. The mechanisms behind ion-engineered water flooding have not been confirmed yet, but there are many proposed mechanisms. Most of the authors believe that the main mechanism behind smart water flooding is the wettability alteration. However, other proposed mechanisms are interfacial tension (IFT) reduction between oil and injected brine, rock dissolution, and electrical double layer expansion. Theoretically, all the mechanisms have an effect on the oil recovery. There are some evidences of success of smart water injection on the field scale. Chemical reactions that happen with injection of smart water are different in sandstone and carbonate reservoirs. It is important to understand how these mechanisms work. In this review paper, the possible mechanisms behind smart water injection into the carbonate reservoir with brief history are discussed.

scholarly journals A Synergy between Controlled Salinity Brine and Biosurfactant Flooding for Improved Oil Recovery: An Experimental Investigation Based on Zeta Potential and Interfacial Tension Measurements

2019 ◽  
Vol 2019 ◽  
pp. 1-15
Author(s):  
Tinuola Udoh ◽  
Jan Vinogradov
Keyword(s):  
Zeta Potential ◽  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
High Salinity ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
All Solutions ◽  
Rock Interface ◽  
Incremental Oil Recovery

In this study, we have investigated the effects of brine and biosurfactant compositions on crude-oil-rock-brine interactions, interfacial tension, zeta potential, and oil recovery. The results of this study show that reduced brine salinity does not cause significant change in IFT. However, addition of biosurfactants to both high and low salinity brines resulted in IFT reduction. Also, experimental results suggest that the zeta potential of high salinity formation brine-rock interface is positive, but oil-brine interface was found to be negatively charged for all solutions used in the study. When controlled salinity brine (CSB) with low salinity and CSB with biosurfactants were injected, both the oil-brine and rock-brine interfaces become negatively charged resulting in increased water-wetness and, hence, improved oil recovery. Addition of biosurfactants to CSB further increased electric double layer expansion which invariably resulted in increased electrostatic repulsion between rock-brine and oil-brine interfaces, but the corresponding incremental oil recovery was small compared with injection of low salinity brine alone. Moreover, we found that the effective zeta potential of crude oil-brine-rock systems is correlated with IFT. The results of this study are relevant to enhanced oil recovery in which controlled salinity waterflooding can be combined with injection of biosurfactants to improve oil recovery.

scholarly journals Experimental study of the performances of commercial surfactants in reducing interfacial tension and wettability alteration in the process of chemical water injection into carbonate reservoirs

2019 ◽  
Vol 10 (4) ◽  
pp. 1551-1563 ◽  
Author(s):  
Siamak Najimi ◽  
Iman Nowrouzi ◽  
Abbas Khaksar Manshad ◽  
Amir H. Mohammadi
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Core Flooding ◽  
Chemical Water

Abstract Surfactants are used in the process of chemical water injection to reduce interfacial tension of water and oil and consequently decrease the capillary pressure in the reservoir. However, other mechanisms such as altering the wettability of the reservoir rock, creating foam and forming a stable emulsion are also other mechanisms of the surfactants flooding. In this study, the effects of three commercially available surfactants, namely AN-120, NX-1510 and TR-880, in different concentrations on interfacial tension of water and oil, the wettability of the reservoir rock and, ultimately, the increase in oil recovery based on pendant drop experiments, contact angle and carbonate core flooding have been investigated. The effects of concentration, temperature, pressure and salinity on the performances of these surfactants have also been shown. The results, in addition to confirming the capability of the surfactants to reduce interfacial tension and altering the wettability to hydrophilicity, show that the TR-880 has the better ability to reduce interfacial tension than AN-120 and NX-1510, and in the alteration of wettability the smallest contact angle was obtained by dissolving 1000 ppm of surfactant NX-1510. Also, the results of interfacial tension tests confirm the better performances of these surfactants in formation salinity and high salinity. Additionally, a total of 72% recovery was achieved with a secondary saline water flooding and flooding with a 1000 ppm of TR-880 surfactant.

Effects of Interfacial Tension Reduction and Wettability Alteration on Oil Recovery by Surfactant Imbibition

2013 ◽  
Vol 868 ◽  
pp. 664-668
Author(s):  
Zi Yuan Qi ◽  
Ye Fei Wang ◽  
Xiao Li Xu
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Spontaneous Imbibition ◽  
Surface Wettability ◽  
Wettability Alteration ◽  
Ionic Surfactants ◽  
Oil Sand ◽  
Sand Surface ◽  
Quartz Sands

Surfactant imbibition experiments were carried out with four surfactants and effects of interfacial tension and surface wettability on oil recovery were studied. A convenient imbibition process with quartz sands was used, and the experimental results suggest that anionic and non-ionic surfactants have higher oil recovery than cationic surfactant, and the sand surface wettability plays an important role in influencing oil recovery during spontaneous imbibition. Altering the wettability of oil sand surface from oil-wet to water-wet can enhance the oil recovery of imbibition process. The maximum ultimate imbibition recovery appeared in the area where both contact angle and interfacial tension were low.

scholarly journals Role of Monovalent and Divalent Ions in Low-Salinity Water Flood in Carbonate Reservoirs: An Integrated Analysis through Zeta Potentiometric and Simulation Studies

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 729
Author(s):  
Paras H. Gopani ◽  
Navpreet Singh ◽  
Hemanta K. Sarma ◽  
Padmaja Mattey ◽  
Vivek R. Srivastava
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Reservoir Simulation ◽  
Saturation Index ◽  
Mineral Dissolution ◽  
Wettability Alteration ◽  
Integrated Analysis ◽  
Simulation Studies ◽  
Low Salinity ◽  
Monovalent Ions

The presence of principal ions in the water injected is essential for enhanced oil recovery by formation of water-wet state in carbonates. This study reaffirms this and presents an evaluation of the positive influence of both divalent as wells as monovalent ions on wettability alteration mechanisms during low salinity waterflooding using brines of varying ionic composition, referred to as “smart brines”. Zeta potentiometric analysis and reservoir simulation studies were conducted with diluted and smart brines that were prepared by varying the composition of principal ions. Surface charge of oil-saturated whole core samples of rock in the presence of various diluted and smart brines was estimated by zeta potential measurements. A comprehensive analysis of zeta potentiometric and reservoir simulation studies was done to establish and investigate the linkage between the recovery mechanism and the incremental recovery achieved. It is noted that zeta potential increases with the increasing level of dilution and it can be attributed to electric double-layer mechanism. On the contrary, simulation studies implied a different mechanism where an increase in effluent’s pH and Ca2+ mole fraction along with decrease in moles of minerals and saturation index implied rock dissolution was dominant mechanism. Moreover, the effect of mineral dissolution beyond the injection block is highly doubtful. This study demonstrates that an integrated approach from both zeta potentiometric and simulation studies can be used to provide insights into the underlying science of interactions at pore scale during a low salinity waterflood using smart brines. With the aid of an adequately designed upscaling procedure and protocol, the laboratory results can be further used towards developing field-scale models to obtain with realistic recovery factors with optimized brine composition and salinity.

scholarly journals Application of ion-engineered Persian Gulf seawater in EOR: effects of different ions on interfacial tension, contact angle, zeta potential, and oil recovery

2021 ◽  
Author(s):  
Amir Hossein Saeedi Dehaghani ◽  
Seyed Masoud Ghalamizade Elyaderani
Keyword(s):  
Contact Angle ◽  
Zeta Potential ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Persian Gulf ◽  
Rock Surface ◽  
Divalent Ions ◽  
Smart Water ◽  
Wet Condition ◽  
The Persian Gulf

AbstractIn this study, we initially performed interfacial tension (IFT) tests to investigate the potential of using the Persian Gulf seawater (PGSW) as smart water with different concentrations of NaCl, KCl, MgCl2, CaCl2, and Na2SO4. Next, for each salt, at the concentration where IFT was minimum, we conducted contact angle, zeta potential, and micromodel flooding tests. The results showed that IFT is minimized if NaCl or KCl is removed from PGSW; thus, for solutions lacking NaCl and KCl, the IFT values were obtained at 26.29 and 26.56 mN/m, respectively. Conversely, in the case of divalent ions, minimum IFT occurred when the concentration of MgCl2, CaCl2, and Na2SO4 in PGSW increased. Specifically, a threefold rise in the concentration of Na2SO4 further reduced IFT as compared to optimal concentrations of MgCl2 or CaCl2. It should be mentioned that eliminating NaCl from PGSW resulted in the lowest IFT value compared to adding or removing other ions. Whereas the removal of NaCl caused the contact angle to decrease from 91.0° to 67.8° relative to PGSW and changed surface wettability to weakly water-wet, eliminating KCl did not considerably change the contact angle, such that it only led to a nine-degree reduction in this angle relative to PGSW and left wettability in the same neutral-wet condition. At optimal concentrations of MgCl2, CaCl2, and Na2SO4, only an increase in Na2SO4 concentration in PGSW could change wettability from neutral-wet to weakly water-wet. For solutions with optimal concentrations, the removal of NaCl or KCl caused the rock surface to have slightly higher negative charges, and increasing the concentration of divalent ions led to a small reduction in the negative charge of the surface. The results of micromodel flooding indicated that NaCl-free PGSW could raise oil recovery by 10.12% relative to PGSW. Furthermore, when the Na2SO4 concentration in PGSW was tripled, the oil recovery increased by 7.34% compared to PGSW. Accordingly, depending on the conditions, it is possible to use PGSW so as to enhance the efficiency of oil recovery by removing NaCl or by increasing the concentration of Na2SO4 three times.

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