scholarly journals High Salinity and High Temperature Stable Colloidal Silica Nanoparticles with Wettability Alteration Ability for EOR Applications

Nanomaterials ◽  
2021 ◽  
Vol 11 (3) ◽  
pp. 707 ◽  
Author(s):  
Nanji J. Hadia ◽  
Yeap Hung Ng ◽  
Ludger Paul Stubbs ◽  
Ole Torsæter
Keyword(s):  
Thermal Stability ◽  
Contact Angle ◽  
High Temperature ◽  
Stability Analysis ◽  
Silica Nanoparticles ◽  
Oil Recovery ◽  
High Salinity ◽  
Angle Measurements ◽  
Accelerated Stability ◽  
Contact Angle Measurements

The stability of nanoparticles at reservoir conditions is a key for a successful application of nanofluids for any oilfield operations, e.g., enhanced oil recovery (EOR). It has, however, remained a challenge to stabilize nanoparticles under high salinity and high temperature conditions for longer duration (at least months). In this work, we report surface modification of commercial silica nanoparticles by combination of zwitterionic and hydrophilic silanes to improve its stability under high salinity and high temperature conditions. To evaluate thermal stability, static and accelerated stability analyses methods were employed to predict the long-term thermal stability of the nanoparticles in pH range of 4–7. The contact angle measurements were performed on aged sandstone and carbonate rock surfaces to evaluate the ability of the nanoparticles to alter the wettability of the rock surfaces. The results of static stability analysis showed excellent thermal stability in 3.5% NaCl brine and synthetic seawater (SSW) at 60 °C for 1 month. The accelerated stability analysis predicted that the modified nanoparticles could remain stable for at least 6 months. The results of contact angle measurements on neutral-wet Berea, Bentheimer, and Austin Chalk showed that the modified nanoparticles were able to adsorb on these rock surfaces and altered wettability to water-wet. A larger change in contact angle for carbonate surface than in sandstone surface showed that these particles could be more effective in carbonate reservoirs or reservoirs with high carbonate content and help improve oil recovery.

Water-Flooding Fluid Diversion Copolymeric Microsphere Prepared by Inverse Suspension Polymerization

e-Polymers ◽  
2007 ◽  
Vol 7 (1) ◽  
Author(s):  
Huang Zhiyu ◽  
Lu Hongsheng ◽  
Zhang Tailiang
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Oil Recovery ◽  
High Salinity ◽  
Suspension Polymerization ◽  
Oil Reservoirs ◽  
Water Flooding ◽  
Toughness Index ◽  
Inverse Suspension Polymerization ◽  
Enhance Oil Recovery

Abstract In order to enhance oil recovery in high-temperature and high-salinity oil reservoirs, the copolymeric microspheres containing acrylamide (AM), acrylonitrile (AN) and AMPS was synthesized by inverse suspension polymerization. The copolymeric microsphere was very uniform and the size could be changed according to the condition of polymerization. The lab-scale studies showed that the copolymeric microsphere exhibit good salt-tolerance and thermal-stability when immersed in 20×105 mg/L NaCl(or KCl) solution, 7500 mg/L CaCl2 (or MgCl2) solution or 2000 mg/L FeCl3 solution, respectively. The copolymeric microsphere showed satisfactory absorbency rates. The sand-pipes experiments confirmed that the average toughness index was 1.059. It could enhance the oil recovery by about 3% compared with the corresponding irregular copolymeric particle.

Effect of Chlorite Clay-Mineral Dissolution on the Improved Oil Recovery From Sandstone Rocks During Diethylenetriaminepentaacetic Acid Chelating-Agent Flooding

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1880-1898 ◽  
Author(s):  
Mohamed Ahmed El-Din Mahmoud
Keyword(s):  
Contact Angle ◽  
Surface Charge ◽  
Clay Minerals ◽  
Oil Recovery ◽  
Chelating Agent ◽  
Oil Reservoirs ◽  
Diethylenetriaminepentaacetic Acid ◽  
Improved Oil Recovery ◽  
Angle Measurements ◽  
Contact Angle Measurements

Summary Sandstone oil reservoirs consist of different clay minerals, such as kaolinite, illite, and chlorite. While these clay minerals can highly affect oil recovery from sandstone oil reservoirs, no attention has been given to investigating the effects of clay minerals during such oil recovery, and no solution has been introduced to alleviate the effects. In this study, and for the first time, the effect of chlorite clay-mineral content on the improved oil recovery (IOR) from different sandstone rock samples was investigated. A new solution was proposed to eliminate the effect of chlorite on the oil recovery from sandstone rocks. Different sandstone cores were used, such as Berea (BSS), Bandera (BND), Kentucky (KSS), and Scioto (SCS) sandstone rocks with different clay minerals. ζ-potential measurements were used to investigate the surface charge of the different clays and different sandstone rocks with different fluids. Fluids such as seawater (SW), low-salinity water (LSW), fresh water, and chelating agents were used. Diethylenetriaminepentaacetic acid (DTPA) chelating agent was introduced to mitigate the chlorite effect on oil recovery from sandstone rocks. The wettability was evaluated using contact-angle measurements and the Amott test for different solutions and different rocks in the presence of actual crude oil. Coreflooding experiments were conducted using these fluids with different sandstone rocks to identify the effect of chlorite on the oil recovery. Coreflooding experiments showed that sandstone cores with high chlorite content yielded the lowest oil recovery when SW and LSW were used. The effect of chlorite on the oil recovery from the two sandstone rocks was minimized with 3 wt% DTPA chelating agent. More oil was recovered in the case of DTPA because of the iron chelation from chlorite. ζ-potential showed that sandstone with high chlorite content has a surface charge close to zero in the case of SW and fresh water. In addition, contact-angle measurements showed that samples with high chlorite content have less water-wetness, which will reduce oil recovery. Contact-angle measurements on chlorite sheets showed that chlorite is oil-wet compared with mica at the same conditions. The addition of high-pH DTPA chelating agent sequestered the iron from the chlorite clay minerals and changed the surface charge to very high negative value, and the contact angle confirmed that the rock changed to water-wet after adding the chelating agent. The Amott index showed that adding DTPA increased the water-wetness for SCS that contains 4 wt% chlorite.

Measurements of the Contact Angles for Various Fluids Which Are Widely Used in the Oilfields to Improve Oil Recovery

2018 ◽  
Author(s):  
M. Elsharafi ◽  
K. Vidal ◽  
R. Thomas
Keyword(s):  
Surface Tension ◽  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Dynamic Contact ◽  
Contact Angles ◽  
Rock Face ◽  
Angle Measurements ◽  
Contact Angle Measurements

Contact angle measurements are important to determine surface and interfacial tension between solids and fluids. A ‘water-wet’ condition on the rock face is necessary in order to extract oil. In this research, the objectives are to determine the wettability (water-wet or oil-wet), analyze how different brine concentrations will affect the wettability, and study the effect of the temperature on the dynamic contact angle measurements. This will be carried out by using the Cahn Dynamic Contact Angle. Analyzer DCA 315 to measure the contact angle between different fluids such as surfactant, alkaline, and mineral oil. This instrument is also used to measure the surface properties such as surface tension, contact angle, and interfacial tension of solid and liquid samples by using the Wilhelmy technique. The work used different surfactant and oil mixed with different alkaline concentrations. Varying alkaline concentrations from 20ml to 1ml were used, whilst keeping the surfactant concentration constant at 50ml.. It was observed that contact angle measurements and surface tension increase with increased alkaline concentrations. Therefore, we can deduce that they are directly proportional. We noticed that changing certain values on the software affected our results. It was found that after calculating the density and inputting it into the CAHN software, more accurate readings for the surface tension were obtained. We anticipate that the surfactant and alkaline can change the surface tension of the solid surface. In our research, surfactant is desirable as it maintains a high surface tension even when alkaline percentage is increased.

scholarly journals Laboratory Study on the Potential EOR Use of HPAM/VES Hybrid in High-Temperature and High-Salinity Oil Reservoirs

2013 ◽  
Vol 2013 ◽  
pp. 1-8 ◽  
Author(s):  
Dingwei Zhu ◽  
Jichao Zhang ◽  
Yugui Han ◽  
Hongyan Wang ◽  
Yujun Feng
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Salinity Tolerance ◽  
Oil Recovery ◽  
High Salinity ◽  
Oil Reservoirs ◽  
Mechanical Degradation ◽  
Core Flooding ◽  
Reservoir Conditions ◽  
Viscoelastic Surfactant

Polymer flooding represents one of the most efficient processes to enhance oil recovery, and partially hydrolyzed polyacrylamide (HPAM) is a widely used oil-displacement agent, but its poor thermal stability, salt tolerance, and mechanical degradation impeded its use in high-temperature and high-salinity oil reservoirs. In this work, a novel viscoelastic surfactant, erucyl dimethyl amidobetaine (EDAB), with improved thermal stability and salinity tolerance, was complexed with HPAM to overcome the deficiencies of HPAM. The HPAM/EDAB hybrid samples were studied in comparison with HPAM and EDAB in synthetic brine regarding their rheological behaviors and core flooding experiments under simulated high-temperature and high-salinity oil reservoir conditions (T: 85°C; total dissolved solids: 32,868 mg/L; [Ca2+] + [Mg2+]: 873 mg/L). It was found that the HPAM/EDAB hybrids exhibited much better heat- and salinity-tolerance and long-term thermal stability than HPAM. Core flooding tests showed that the oil recovery factors of HPAM/EDAB hybrids are between those of HPAM and EDAB. These results are attributed to the synergistic effect between HPAM and EDAB in the hybrid.

scholarly journals Toward a mechanistic understanding of wettability alteration in reservoir rocks using silica nanoparticles

2019 ◽  
Vol 89 ◽  
pp. 03004 ◽  
Author(s):  
Saeed Jafari Daghlian Sofla ◽  
Lesley Anne James ◽  
Yahui Zhang
Keyword(s):  
Contact Angle ◽  
Silica Nanoparticles ◽  
Naphthenic Acids ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Angle Measurements ◽  
Contact Angle Measurements ◽  
Rock Interface ◽  
The Impact

Traditional concepts of simple liquid spreading may not apply to nanoparticle-fluids. Most investigations pertaining to the wettability alteration of solid surfaces due to the presence of nanoparticles in the fluid are oversimplified, i.e. nanoparticles dispersed in DI-water and smooth, homogeneous, and clean surfaces have been used. From a practical enhanced oil recovery (EOR) point of view, the nanoparticles must be dispersed in either seawater or high salinity formation water containing diverse types and concentrations of ions. These ions interact with the electrostatic properties of the nanoparticles. Likewise, the oil phase may contain many surface active components like asphaltene and naphthenic acids which can interact with nanoparticles at oil-water and oil-rock interface. In reality, the rock sample is a heterogeneous, non-smooth, mixed-wet substrate with a diverse mineralogical composition. The electrical charge of minerals can vary when contacted with an ionic fluid. This can alter the electrostatic repulsion between substrate and nanoparticles and consequently the substrate can either attract or repel charged particles, including nanoparticles. Hence, the role of nanoparticles must be evaluated considering multicomponent complex fluids and real formation rock. Despite numerous reports regarding the wettability alteration of reservoir rock from oil-wet to water-wet by nanoparticles, some inherent limitations in the wettability alteration experiments prevent conclusions about the performance of nanoparticles in practical complex conditions. For instance, the wettability alteration by nanoparticles is often determined by contact angle measurements. In this method, the substrates are either aged with (immersed in) nanoparticle-fluids before conducting the experiments or contacted with nanoparticle-fluids before attachment of the oil droplet on the rock surface. Hence, in both cases, before initiating the contact angle measurements, the nanoparticles would already exist at the oil-rock interface possibly giving inaccurate measurements. The objective of this work is to investigate the mechanism of wettability alteration by silica nanoparticles pre-existing on the rock interface (conventional contact angle measurements) and using a new displacement contact angle method to better mimic the scenario of injecting a nanoparticle fluid into the reservoir already containing formation brine. The impact of pre-existing nanoparticles at the oil-rock interface (in the conventional contact angle measurements) on the contact angle measurements are examined for simple (n-decane, NaCl brine, and pure substrates) and complex (crude oil, seawater, and reservoir rock) systems on various wetting conditions of substrates (water-wet and oil-wet). The nanoparticles are dispersed in seawater using our H+ protected method [1]. Then, the effect of surface and nanoparticle charge on the contact angle is evaluated by adjusting the aqueous phase salinity. We also differentiate between the disjoining pressure mechanism and diffusion of silica nanoparticles through the oil phase by testing the attachment of nanoparticles on the rock surface.

scholarly journals Wettability Alteration in High-Temperature and High-Salinity Carbonate Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 18 (04) ◽  
pp. 646-655 ◽  
Author(s):  
Gaurav Sharma ◽  
Kishore K. Mohanty
Keyword(s):  
Contact Angle ◽  
High Temperature ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
High Salinity ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Surfactant Systems ◽  
Original Oil In Place ◽  
Harsh Conditions

Summary The goal of this work was to change the wettability of a carbonate rock from mixed-wet toward water-wet at high temperature and high salinity. Three types of surfactants in dilute concentrations (<0.2 wt%) were used. Initial surfactant screening was performed on the basis of aqueous stability at these harsh conditions. Contact-angle experiments on aged calcite plates were conducted to narrow the list of surfactants, and spontaneous-imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was carried out in cores with and without the wettability-altering surfactants. It was observed that most but not all surfactants were aqueous-unstable by themselves at these harsh conditions. Dual-surfactant systems, mixtures of a nonionic and a cationic surfactant, increased the aqueous stability. Some of the dual-surfactant systems proved effective for wettability alteration and could recover could recover 70 to 80% OOIP (original oil in place) during spontaneous imbibition. Secondary waterflooding with the wettability-altering surfactant increased the oil recovery over the waterflooding without the surfactants (from 29 to 40% of OOIP).

Wettability Determination by Equilibrium Contact Angle Measurements: Reservoir Rock- Connate Water System With Injection of CO2

2012 ◽  
Author(s):  
Narjes Shojaikaveh ◽  
Cas Berentsen ◽  
Susanne Eva Johanne Rudolph-Floter ◽  
Karl Heinz Wolf ◽  
William Richard Rossen
Keyword(s):  
Contact Angle ◽  
Water System ◽  
Reservoir Rock ◽  
Equilibrium Contact Angle ◽  
Connate Water ◽  
Angle Measurements ◽  
Contact Angle Measurements

Surface Wettability Enhances Osteoblast Adhesion on Silicon-Substituted Hydroxyapatite Thin Films

2007 ◽  
Vol 330-332 ◽  
pp. 877-880 ◽  
Author(s):  
E.S. Thian ◽  
J. Huang ◽  
Serena Best ◽  
Zoe H. Barber ◽  
William Bonfield
Keyword(s):  
Thin Films ◽  
Contact Angle ◽  
Actin Filaments ◽  
Culture Study ◽  
Cell Culture Study ◽  
Angle Measurements ◽  
Contact Angle Measurements ◽  
Osteoblast Adhesion ◽  
Lower Contact

Crystalline hydroxyapatite (HA) and 0.8 wt.% silicon-substituted HA (SiHA) thin films were produced using magnetron co-sputtering. These films were subjected to contact angle measurements and in vitro cell culture study using human osteoblast-like (HOB) cells. A wettability study showed that SiHA has a lower contact angle, and thus is more hydrophilic in nature, as compared to HA. Consequently, enhanced cell growth was observed on SiHA at all time-points. Furthermore, distinct and well-developed actin filaments could be seen within HOB cells on SiHA. Thus, this work demonstrated that the surface properties of the coating may be modified by the substitution of Si into the HA structure.

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