Experimental Investigation of Water Incompatibility and Rock/Fluid and Fluid/Fluid Interactions in the Absence and Presence of Scale Inhibitors

SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2615-2631 ◽  
Author(s):  
Mehdi Mohammadi ◽  
Siavash Riahi
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Water System ◽  
Contact Angles ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Environmental Scanning ◽  
Interfacial Behavior ◽  
Behavior Study ◽  
Fluid Interactions

Summary Waterflooding is known as an affordable method to enhance oil recovery after primary depletion. However, the chemical incompatibility between injected water and the water in the reservoir may cause the formation of mineral scales. The most effective method for managing such a problem is to use a variety of scale inhibitors (SIs) along with a waterflooding plan. It is necessary to perform a comprehensive study on the incompatibility scaling issue for the candidate-brine/SI formulations, and also their effect on the reservoir-rock/fluid characteristics. In this study, both in the absence and presence of polymeric, phosphonate, and polyphosphonate SIs, the scaling tendency (ST) of different brines is evaluated through experimental and simulation works. Drop-shape analysis (DSA), environmental-scanning-electronic-microscopy (ESEM) observation, energy-dispersive X-ray (EDX) analysis, and microemulsion phase behavior are also used to study the effect of different brine/SI formulations on the rock/fluid and fluid/fluid interactions, through wettability and interfacial-tension (IFT) evaluation. In summary, sulfate (SO42−) was identified as the most problematic ion in the formulation of injected water that causes the formation of solid scales upon mixing with the cation-rich formation water (FW). In the case of SIs, solid precipitation was shifted toward a lower value, with more pronounced effects at higher SI concentrations. At different ionic compositions, the inhibition efficiency (IE%) of all SIs ranged from 16 to 50% at [SI]  = 20 ppm and 38 to 81% at [SI] = 50 ppm. In general, phosphonates worked better (i.e., higher IE value) than polymeric SI. Measuring contact angles along with ESEM/EDX data also illustrated the positive effect of SIs on the wettability alteration of the aged carbonate substrates. In the absence of SIs, the contact angles for different brines were in the range of 70° ≤ θ ≤ 104°, whereas these values fell between 35 and 80° for systems containing 50 ppm of SI. In addition, phase-behavior study and IFT measurement illustrated a salinity-dependence effect of SIs on the interfacial behavior of the oil/water system.

Phase Behavior, Wettability Alteration, and Oil Recovery of Low-Salinity Surfactant Solutions in Carbonate Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1784-1802 ◽  
Author(s):  
Sepideh Veiskarami ◽  
Arezou Jafari ◽  
Aboozar Soleymanzadeh
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Study Phase ◽  
Low Salinity ◽  
Angle Measurements ◽  
Contact Angle Measurements ◽  
Favorable State ◽  
Phase Behaviors ◽  
The Impact

Summary Recent investigations have shown that treatment with injected brine composition can improve oil production. Various mechanisms have been suggested to go through the phenomenon; nevertheless, wettability alteration is one of the most commonly proposed mechanisms in the literature. Wettability alteration of the porous media toward a more favorable state reduces the capillary pressure, consequently contributing to the oil detachment from pore walls. In this study, phase behavior, oil recovery, and wettability alteration toward a more favorable state were investigated using a combination of formulations of surfactant and modified low-salinity (LS) brine. Phase behaviors of these various formulations were examined experimentally through observations on relative phase volumes. Experiments were performed in various water/oil ratios (WORs) in the presence of two different oil samples, namely C1 and C2. These experiments were conducted to clarify the impact of each affecting parameter; in particular, the impact of resin and asphaltene of crude oil on the performance of LS surfactant (LSS) flooding. Hereafter, the optimal formulation was flooded into the oil-wet micromodel. Optimum formulations increased the capillary number more than four orders of magnitude higher than that under formation brine (FB) flooding, thus causing oil recovery rates of 61 and 67% for oil samples C1 and C2, respectively. Likewise, the wettability alteration potential of optimized formulations was studied through contact angle measurements. Results showed that LS and LSS solutions could act as possible wettability alternating methods for oil-wet carbonate rocks. Using the optimum formulation resulted in a wettability alteration index (WAI) of 0.66 for sample C1 and 0.49 for sample C2, while using LS brine itself ended in 0.51 and 0.29 for oil samples C1 and C2, respectively.

Influence of New SiO2 Nanofluids on Surface Wettability and Interfacial Tension Behaviour between Oil-Water Interface in EOR Processes

2013 ◽  
Vol 26 ◽  
pp. 1-8 ◽  
Author(s):  
A. Amraei ◽  
Zahra Fakhroueian ◽  
Alireza Bahramian
Keyword(s):  
Surface Tension ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Ph Value ◽  
Pure Water ◽  
Contact Angles ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Water Interface ◽  
Eor Processes

Fine SiO2 nanosphericals (2-5nm) and new various stable nanofluids including Tween 80, Span 80, Lauric alcohol-3EO, CTAB, SDS and K-Laurate surfactants in water or paraffin based solution were used as new SiO2 nanoproducts in oil recovery. These nanofluids can strongly change oil-wet carbonate reservoir rock to complete water-wet wettability and showed an excellent trend of surface tension (S.T) and IFT (interfacial tension) reduction in comparison with pure water and reference solutions. The CaCO3 plates reservoir was then aged for 2, 5 and 8 days into the 1, 3 and 8% of different concentrations of synthesized SiO2 nanofluids (effect of various concentrations via different aging time). Air/water and n-decane/water contact angles on oil-wet and clean carbonate rock aged in designed SiO2 nanofluids were measured and the pH value as a significant factor estimated. The interesting influence of microwave irradiation on surface tension and IFT including various SiO2 nanofluids was investigated after 12 min which some of the especial nanofluid concentrations showed successful reduction. Our findings indicated the important effect of temperature over decreasing of surface tension and IFT between oil and water interface including SiO2 nanofluids after annealing at 70°C. Therefore, this phenomenon can be significantly capable and valuable in applying of new technology in the fabrication of novel nanofluids in EOR processes and saving source of energy regarding to conventional production.

A Mechanistic Model for Wettability Alteration by Chemically Tuned Waterflooding in Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 767-783 ◽  
Author(s):  
C.. Qiao ◽  
L.. Li ◽  
R.T.. T. Johns ◽  
J.. Xu
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Reactive Transport ◽  
Mechanistic Model ◽  
Contact Angles ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Physical Parameters ◽  
Minor Effect

Summary Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to more-water-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidic-oil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2+, Mg2+) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2+ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

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 Role of Phase-Dependent Dielectric Properties of Alumina Nanoparticles in Electromagnetic-Assisted Enhanced Oil Recovery

Nanomaterials ◽  
2020 ◽  
Vol 10 (10) ◽  
pp. 1975 ◽  
Author(s):  
Muhammad Adil ◽  
Kean Chuan Lee ◽  
Hasnah Mohd Zaid ◽  
Takaaki Manaka
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Metal Oxide Nanoparticles ◽  
Dielectric Behavior ◽  
Mobility Ratio ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Alumina Nanoparticles ◽  
Recovery Mechanism ◽  
Al2o3 Nps

The utilization of metal-oxide nanoparticles in enhanced oil recovery (EOR) has generated considerable research interest to increase the oil recovery. Among these nanoparticles, alumina nanoparticles (Al2O3-NPs) have proved promising in improving the oil recovery mechanism due to their prominent thermal properties. However, more significantly, these nanoparticles, coupled with electromagnetic (EM) waves, can be polarized to reduce water/oil mobility ratio and create disturbances at the oil/nanofluid interface, so that oil can be released from the reservoir rock surfaces and travelled easily to the production well. Moreover, alumina exists in various transition phases (γ, δ, θ, κ, β, η, χ), providing not only different sizes and morphologies but phase-dependent dielectric behavior at the applied EM frequencies. In this research, the oil recovery mechanism under EM fields of varying frequencies was investigated, which involved parameters such as mobility ratio, interfacial tension (IFT) and wettability. The displacement tests were conducted in water-wet sandpacks at 95 °C, by employing crude oil from Tapis. Alumina nanofluids (Al2O3-NFs) of four different phases (α, κ, θ and γ) and particle sizes (25–94.3 nm) were prepared by dispersing 0.01 wt. % NPs in brine (3 wt. % NaCl) together with SDBS as a dispersant. Three sequential injection scenarios were performed in each flooding scheme: (i) preflushes brine as a secondary flooding, (ii) conventional nano/EM-assisted nanofluid flooding, and (iii) postflushes brine to flush NPs. Compared to conventional nanofluid flooding (3.03–11.46% original oil in place/OOIP) as incremental oil recovery, EM-assisted nanofluid flooding provided an increase in oil recovery by approximately 4.12–12.90% of OOIP for different phases of alumina. It was established from these results that the recovery from EM-assisted nanofluid flooding is itself dependent on frequency, which is associated with good dielectric behavior of NPs to formulate the oil recovery mechanism including (i) mobility ratio improvement due to an electrorheological (ER) effect, (ii) interfacial disturbances by the oil droplet deformation, and (iii) wettability alteration by increased surface-free energy.

Enhancing hydrocarbon productivity via wettability alteration: a review on the application of nanoparticles

2019 ◽  
Vol 35 (4) ◽  
pp. 531-563 ◽  
Author(s):  
Asefe Mousavi Moghadam ◽  
Mahsa Baghban Salehi
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Review Paper ◽  
Oil And Gas Industry ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Main Element ◽  
Preparation Methods ◽  
Hydrocarbon Production ◽  
Rock Types

AbstractWettability alteration (WA) of reservoir rock is an attractive topic in the upstream oil and gas industry, for the improvement of hydrocarbon production. Novel methods and chemicals that may change the wetting state of reservoir rock to water-wet have highly attracted petroleum researchers’ attention. Use of nanoparticles might be matured enough in different branches of sciences but in WA is still young, which increased in recent decades. This review paper presents a comprehensive review on WA, especially in terms of nanoparticle application in increasing oil recovery. Therefore, the areas of controversy of two rock types (carbonate and sandstone) as a main element in WA are discussed. A selection of reviewed nanoparticle types, preparation methods, and effective factors was also investigated. Moreover, two main methods of WA, static and dynamic, are highlighted. Although these methods have been discussed in many reviews, a clear classification form of these has not been considered. Such comprehensive arrangement is presented in this review, specifically on nanoparticle application. Moreover, coreflooding tests of different fluid types and injection scenarios are discussed. The review indicates promising use of nanoparticles in increasing ultimate oil recovery. It was hoped the current review paper can provide useful related reference to study WA via nanoparticle application.

scholarly journals Synthesis, Characterization, and Assessment of a CeO2@Nanoclay Nanocomposite for Enhanced Oil Recovery

Nanomaterials ◽  
2020 ◽  
Vol 10 (11) ◽  
pp. 2280
Author(s):  
Mohammad Javad Nazarahari ◽  
Abbas Khaksar Manshad ◽  
Siyamak Moradi ◽  
Ali Shafiei ◽  
Jagar Abdulazez Ali ◽  
...  
Keyword(s):  
Zeta Potential ◽  
Surface Morphology ◽  
Oil Recovery ◽  
Petroleum Reservoirs ◽  
Fluorite Structure ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
The Novel ◽  
X Ray ◽  
Sandstone Reservoir

In this paper, synthesis and characterization of a novel CeO2/nanoclay nanocomposite (NC) and its effects on IFT reduction and wettability alteration is reported in the literature for the first time. The NC was characterized using scanning electron microscopy (SEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), energy-dispersive X-ray spectroscopy (EDS), and EDS MAP. The surface morphology, crystalline phases, and functional groups of the novel NC were investigated. Nanofluids with different concentrations of 100, 250, 500, 1000, 1500, and 2000 ppm were prepared and used as dispersants in porous media. The stability, pH, conductivity, IFT, and wettability alternation characteristics of the prepared nanofluids were examined to find out the optimum concentration for the selected carbonate and sandstone reservoir rocks. Conductivity and zeta potential measurements showed that a nanofluid with concentration of 500 ppm can reduce the IFT from 35 mN/m to 17 mN/m (48.5% reduction) and alter the contact angle of the tested carbonate and sandstone reservoir rock samples from 139° to 53° (38% improvement in wettability alteration) and 123° to 90° (27% improvement in wettability alteration), respectively. A cubic fluorite structure was identified for CeO2 using the standard XRD data. FESEM revealed that the surface morphology of the NC has a layer sheet morphology of CeO2/SiO2 nanocomposite and the particle sizes are approximately 20 to 26 nm. TGA analysis results shows that the novel NC has a high stability at 90 °C which is a typical upper bound temperature in petroleum reservoirs. Zeta potential peaks at concentration of 500 ppm which is a sign of stabilty of the nanofluid. The results of this study can be used in design of optimum yet effective EOR schemes for both carbobate and sandstone petroleum reservoirs.

Modeling Contact Angle vs. Temperature for the Quartz-Water-Decane System

SPE Journal ◽  
2021 ◽  
pp. 1-13
Author(s):  
Timothy S. Duffy ◽  
Isaac K. Gamwo ◽  
Russell T. Johns ◽  
Serguei N. Lvov
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Elevated Temperatures ◽  
Van Der Waals ◽  
Water System ◽  
Contact Angles ◽  
Ambient Conditions ◽  
Temperature Dependent ◽  
Acid Base ◽  
Ambient Temperatures

Summary Innovative approaches are needed to improve the efficiency of oil recovery technologies to meet the growing demands of fossil-fuel based energy consumption. Enhanced oil recovery (EOR) methods such as low-salinity waterflooding and chemically tuned waterflooding aim to optimize the reservoir’s wetting properties, detaching oil globules from rock surfaces and allowing easier oil flow through pore throats. This wetting behavior is commonly quantified by contact angle measurements of the rock-oil-brine interface, which have been thoroughly investigated and theorized for many systems at ambient temperatures and pressures. However, few studies exist for extending contact angle theories away from ambient conditions. In this paper, we model the contact angles of a quartz-water-decane system at elevated temperatures using the surface tension component (STC) approach. Temperature-dependent van der Waals [Lifshitz-van der Waals (LW)] interactions and hydrogen-bonding (acid-base) interactions were calculated and are incorporated into the model for the quartz-water-decane interface. The Hough and White procedure was used to create temperature-dependent dielectric functions of quartz, water, and normal decane for calculations of Hamaker coefficients. Hamaker coefficients calculated this way are highly linear with temperature and agree well with Israelachvili’s approximation. The acid-base interactions likely contribute the most to system wettability changes. Resulting contact angles of the quartz-water-decane system shift from water-wet (16°) to slightly water-wet (57.4°) as temperature increases. The model was also successfully verified for the quartz-air-water system. Our results can be used in future studies to determine optimal injected water compositions for specific rock-oil-brine and other systems with consideration of reservoir temperature.

Dynamic Interfacial Tension Behavior of Pure and Binary Surfactant System

2020 ◽  
Vol 17 (2) ◽  
pp. 1251-1259
Author(s):  
Nur Asyraf Md Akhir ◽  
Ismail Mohd Saaid ◽  
Ahmad Kamal Idris ◽  
Anita Ramli ◽  
Nurul Amirah Ismail ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Physicochemical Properties ◽  
Oil Recovery ◽  
Liquid Crystalline ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Pure System ◽  
Dynamic Interfacial Tension ◽  
Surfactant System ◽  
Internal Olefin Sulfonate

Surfactants are very important surface-active agents in implementation of chemical enhanced oil recovery for oil-water interfacial tension and wettability alteration. However, the high adsorption of surfactant on reservoir rock reduces the efficiency of surfactant flooding. Conventionally, inorganic alkali has been introduced to reduce adsorption of surfactant, but alkali will lead to the formation of emulsion, formation damage and scaling. Therefore, lignosulfonate, a sacrificial agent has been introduced as an alternative to inorganic alkali. In this paper, the critical micelle concentration (CMC) and dynamic interfacial tension (IFT) behavior of a pure and binary system of internal olefin sulfonate (IOS) and lignosulfonate (LS) at brine-decane interfaces are determined by using a spinning drop method. The physicochemical properties of pure and binary of IOS and LS system are determined by conductivity and pH measurements. The CMC value of IOS in 3.5 wt% brine salinity is higher compared to LS due to the isomeric branched of IOS which can occupy a larger area per molecules. The dynamic interfacial tension of IOS shows the fast adsorption of surfactant molecules to the brine-decane interfaces. This is indicated by the fast equilibrium interfacial tension reached by IOS. In comparison, the LS pure system shows decreasing behavior of dynamic interfacial tension. The fast adsorption at the interfaces is only reached for higher LS concentrations. The synergy effect between IOS and LS system shows a reduction in the interfacial value with LS optimum concentration of 0.6 wt%. The drop in conductivity and pH values indicated the development of a tightly packed lamellar liquid crystalline structure. These physicochemical properties are in agreement with the dynamic interfacial tension behavior of the IOS and LS system. This study has demonstrated the significant impact of the LS addition in reducing the dynamic interfacial tension of the surfactant system.

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