The Potential of Sulfate as Optimizer of Crude Oil-Water Interfacial Rheology to Increase Oil Recovery During Smart Water Injection in Carbonates

2016 ◽  
Author(s):  
Griselda Garcia-Olvera ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Water Injection ◽  
Interfacial Rheology ◽  
Smart Water ◽  
Oil Water

scholarly journals The Oscillatory Spinning Drop Technique. An Innovative Method to Measure Dilational Interfacial Rheological Properties of Crude Oil-Brine Systems in the Presence of Asphaltenes

2021 ◽  
Vol 5 (3) ◽  
pp. 42
Author(s):  
Ronald Marquez ◽  
Johnny Bullon ◽  
Ana Forgiarini ◽  
Jean-Louis Salager
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Rheological Properties ◽  
Oil Recovery ◽  
Interfacial Rheology ◽  
Drop Method ◽  
Natural Surfactants ◽  
Low Interfacial Tension ◽  
Oil Water ◽  
Drop Technique

The oscillatory spinning drop method has been proven recently to be an accurate technique to measure dilational interfacial rheological properties. It is the only available equipment for measuring dilational moduli in low interfacial tension systems, as it is the case in applications dealing with surfactant-oil-water three-phase behavior like enhanced oil recovery, crude oil dehydration, or extreme microemulsion solubilization. Different systems can be studied, bubble-in-liquid, oil-in-water, microemulsion-in-water, oil-in-microemulsion, and systems with the presence of complex natural surfactants like asphaltene aggregates or particles. The technique allows studying the characteristics and properties of water/oil interfaces, particularly when the oil contains asphaltenes and when surfactants are present. In this work, we present a review of the measurements of crude oil-brine interfaces with the oscillating spinning drop technique. The review is divided into four sections. First, an introduction on the oscillating spinning drop technique, fundamental and applied concepts are presented. The three sections that follow are divided according to the complexity of the systems measured with the oscillating spinning drop, starting with simple surfactant-oil-water systems. Then the complexity increases, presenting interfacial rheology properties of crude oil-brine systems, and finally, more complex surfactant-crude oil-brine systems are reviewed. We have found that using the oscillating spinning drop method to measure interfacial rheology properties can help make precise measurements in a reasonable amount of time. This is of significance when systems with long equilibration times, e.g., asphaltene or high molecular weight surfactant-containing systems are measured, or with systems formulated with a demulsifier which is generally associated with low interfacial tension.

scholarly journals A Reheat Gas Turbine Oilfield Cogeneration System, Fueled With Heavy Crude Oil, Which Produces Very Low NOx Emissions

1987 ◽  
Author(s):  
Frederick E. Moreno ◽  
Philip J. Divirgilio
Keyword(s):  
Crude Oil ◽  
Gas Turbine ◽  
Steam Generator ◽  
Oil Recovery ◽  
Catalytic Reduction ◽  
Water Injection ◽  
Industrial Process ◽  
Field Testing ◽  
Nox Emissions ◽  
Cogeneration System

A gas turbine cogeneration system is described that offers fuel flexibility plus substantially reduced NOx emissions without water injection or selective catalytic reduction (SCR). The entirely new turbine design developed by TurboEnergy Systems permits boiler repowering and other cogeneration applications. The first application will be in the California heavy oilfields; the system will be retrofitted to an existing 50 million btu/hr oilfield steam generator used in thermally enhanced oil recovery. The turbine, rated at 1250 kw (site output), was sized to match the combustion air flow requirements of the steam generator. A reheated design was selected to maximize power output from the limited airflow available and to maximize the exhaust temperature for cogeneration and industrial process applications. The oilfield cogeneration system being developed includes a new heavy oil burner for the steam generator which will be fired on the high temperature exhaust from the turbine. The system will also provide low NOx emissions, below the tightest projected standards in Kern County, which has a large concentration of heavy oilfields. Both the turbine and the steam generator burner will burn heavy (API 13 gravity) crude oil. The paper describes the overall system, its interface with the existing process, the design techniques used, and presents performance projections. Field testing will begin at a site near Bakersfield, California, starting in early to mid-1987.

scholarly journals A Surface Complexation Model of Alkaline-SmartWater Electrokinetic Interactions in Carbonates

2020 ◽  
Vol 146 ◽  
pp. 02003
Author(s):  
Moataz Abu-Al-Saud ◽  
Amani Al-Ghamdi ◽  
Subhash Ayirala ◽  
Mohammed Al-Otaibi
Keyword(s):  
Experimental Data ◽  
Zeta Potential ◽  
Crude Oil ◽  
Oil Recovery ◽  
Surface Complexation ◽  
Surface Complexation Model ◽  
Zeta Potentials ◽  
Smart Water ◽  
Injection Water ◽  
Carbonate Formations

Understanding the effect of injection water chemistry is becoming crucial, as it has been recently shown to have a major impact on oil recovery processes in carbonate formations. Various studies have concluded that surface charge alteration is the primary mechanism behind the observed change of wettability towards water-wet due to SmartWater injection in carbonates. Therefore, understanding the surface charges at brine/calcite and brine/crude oil interfaces becomes essential to optimize the injection water compositions for enhanced oil recovery (EOR) in carbonate formations. In this work, the physicochemical interactions of different brine recipes with and without alkali in carbonates are evaluated using Surface Complexation Model (SCM). First, the zeta-potential of brine/calcite and brine/crude oil interfaces are determined for Smart Water, NaCl, and Na2SO4 brines at fixed salinity. The high salinity seawater is also included to provide the baseline for comparison. Then, two types of Alkali (NaOH and Na2CO3) are added at 0.1 wt% concentration to the different brine recipes to verify their effects on the computed zeta-potential values in the SCM framework. The SCM results are compared with experimental data of zeta-potentials obtained with calcite in brine and crude oil in brine suspensions using the same brines and the two alkali concentrations. The SCM results follow the same trends observed in experimental data to reasonably match the zeta-potential values at the calcite/brine interface. Generally, the addition of alkaline drives the zeta-potentials towards more negative values. This trend towards negative zeta-potential is confirmed for the Smart Water recipe with the impact being more pronounced for Na2CO3 due to the presence of divalent anion carbonate (CO3)-2. Some discrepancy in the zeta-potential magnitude between the SCM results and experiments is observed at the brine/crude oil interface with the addition of alkali. This discrepancy can be attributed to neglecting the reaction of carboxylic acid groups in the crude oil with strong alkali as NaOH and Na2CO3. The novelty of this work is that it clearly validates the SCM results with experimental zeta-potential data to determine the physicochemical interaction of alkaline chemicals with SmartWater in carbonates. These modeling results provide new insights on defining optimal SmartWater compositions to synergize with alkaline chemicals to further improve oil recovery in carbonate reservoirs.

Effect of acid number of crude oil on oil recovery of smart water coupled with silica nanoparticles

2018 ◽  
Vol 36 (5) ◽  
pp. 343-349 ◽  
Author(s):  
Saeed Ashtari Larki ◽  
Hooman Banashooshtari ◽  
Hassan Shokrollahzadeh Behbahani ◽  
Adel Najafi-Marghmaleki
Keyword(s):  
Crude Oil ◽  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Acid Number ◽  
Smart Water

scholarly journals Experimental Investigation on Oil Enhancement Mechanism of Hot Water Injection in tight reservoirs

Open Physics ◽  
2016 ◽  
Vol 14 (1) ◽  
pp. 703-713 ◽  
Author(s):  
Hao Yongmao ◽  
Lu Mingjing ◽  
Dong Chengshun ◽  
Jia Jianpeng ◽  
Su Yuliang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Water Injection ◽  
Hot Water ◽  
Water Flooding ◽  
Water Displacement ◽  
Pore Characteristics ◽  
Irreducible Water Saturation ◽  
Tight Reservoirs ◽  
Oil Water

AbstractAimed at enhancing the oil recovery of tight reservoirs, the mechanism of hot water flooding was studied in this paper. Experiments were conducted to investigate the influence of hot water injection on oil properties, and the interaction between rock and fluid, petrophysical property of the reservoirs. Results show that with the injected water temperature increasing, the oil/water viscosity ratio falls slightly in a tight reservoir which has little effect on oil recovery. Further it shows that the volume factor of oil increases significantly which can increase the formation energy and thus raise the formation pressure. At the same time, oil/water interfacial tension decreases slightly which has a positive effect on production though the reduction is not obvious. Meanwhile, the irreducible water saturation and the residual oil saturation are both reduced, the common percolation area of two phases is widened and the general shape of the curve improves. The threshold pressure gradient that crude oil starts to flow also decreases. It relates the power function to the temperature, which means it will be easier for oil production and water injection. Further the pore characteristics of reservoir rocks improves which leads to better water displacement. Based on the experimental results and influence of temperature on different aspects of hot water injection, the flow velocity expression of two-phase of oil and water after hot water injection in tight reservoirs is obtained.

scholarly journals Interfacial Phenomena Effect on Sand Production Due to Optimized Smart Water with/without the Presence of Nanoparticles

2020 ◽  
Vol 10 (6) ◽  
pp. 6652-6668
Keyword(s):  
Oil Recovery ◽  
High Efficiency ◽  
Low Cost ◽  
Water Injection ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Sand Production ◽  
Smart Water ◽  
Comparison Of The Results

Historically, smart water flooding is proved as one of the methods used to enhance oil recovery from hydrocarbon reservoirs. This method has been spread due to its low cost and ease of operation, with changing the composition and concentration of salts in the water, the smart water injection leads to more excellent compatibility with rock and fluids. However, due to a large number of sandstone reservoirs in the world and the increase of the recovery factor using this high-efficiency method, a problem occurs with the continued injection of smart water into these reservoirs a phenomenon happened in which called rock leaching. Indeed, sand production is the most common problem in these fields. Rock wettability alteration toward water wetting is considered as the main cause of sand production during the smart water injection mechanism. During this process, due to stresses on the rock surface as well as disturbance of equilibrium, the sand production in the porous media takes place. In this paper, the effect of wettability alteration of oil wetted sandstones (0.005,0.01,0.02 and 0.03 molar stearic acid in normal heptane) on sand production in the presence of smart water is fully investigated. The implementation of an effective chemical method, which is nanoparticles, have been executed to prevent sand production. By stabilizing silica nanoparticles (SiO2) at an optimum concentration of 2000 ppm in smart water (pH=8) according to the results of Zeta potential and DLS test, the effect of wettability alteration of oil wetted sandstones on sand production in the presence of smart water with nanoparticles is thoroughly reviewed. Ultimately, a comparison of the results showed that nanoparticles significantly reduced sand production.

Microscale Interactions of Surfactant and Polymer Chemicals at Crude Oil/Water Interface for Enhanced Oil Recovery

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1812-1826
Author(s):  
Subhash Ayirala ◽  
Zuoli Li ◽  
Rubia Mariath ◽  
Abdulkareem AlSofi ◽  
Zhenghe Xu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
High Salinity ◽  
Interfacial Shear ◽  
Experimental Techniques ◽  
Water Interface ◽  
Oil Droplets ◽  
Interfacial Film ◽  
Chemical Eor ◽  
Oil Water

Summary The conventional experimental techniques used for performance evaluation of enhanced oil recovery (EOR) chemicals, such as polymers and surfactants, have been mostly limited to bulk viscosity, phase behavior/interfacial tension (IFT), and thermal stability measurements. Furthermore, fundamental studies exploring the different microscale interactions instigated by the EOR chemicals at the crude oil/water interface are scanty. The objective of this experimental study is to fill this existing knowledge gap and deliver an important understanding on underlying interfacial sciences and their potential implications for oil recovery in chemical EOR. Different microscale interactions of EOR chemicals, at crude oil/water interface, were studied by using a suite of experimental techniques, including an interfacial shear rheometer, Langmuir trough, and coalescence time measurement apparatus at both ambient (23°C) and elevated (70°C) temperatures. The reservoir crude oil and high-salinity injection water (57,000 ppm total dissolved solids) were used. Two chemicals, an amphoteric surfactant (at 1,000 ppm) and a sulfonated polyacrylamide polymer (at 500 and 700 ppm) were chosen because they are tolerant to high-salinity and high-temperature conditions. Interfacial viscous and elastic moduli (viscoelasticity), interface pressures, interface compression energies, and coalescence time between crude oil droplets are the major experimental data measured. Interfacial shear rheology results showed that surfactant favorably reduced the viscoelasticity of crude oil/water interface by decreasing the elastic and viscous modulus and increasing the phase angle to soften the interfacial film. Polymers in brine either alone or together with surfactant increased the viscous and elastic modulus and decreased the phase angle at the oil/water interface, thereby contributing to interfacial film rigidity. Interfacial pressures with polymers remained almost in the same order of magnitude as the high-salinity brine. In contrast, a significant reduction in interfacial pressures with surfactant was observed. The interface compression energies indicated the same trend and were reduced by approximately two orders of magnitude when surfactant was added to the brine. The surfactant was also able to retain similar interface behavior under compression even in the presence of polymers. The coalescence times between crude oil droplets were increased by polymers, while they were substantially decreased by the surfactant. These consistent findings from different experimental techniques demonstrated the adverse interactions of polymers at the crude oil/water interface to result in more rigid films, while confirming the high efficiency of the surfactant to soften the interfacial film, promote the oil droplets coalescence, and mobilize substantial amounts of residual oil in chemical EOR. This experimental study, for the first time, characterized the microscale interactions of surfactant-polymer chemicals at the crude oil/water interface. The applicability of several interfacial experimental techniques has been demonstrated to successfully understand underlying interfacial sciences and oil mobilization mechanisms in chemical EOR. These techniques and methods can provide potential means to efficiently screen and optimize EOR chemical formulations for better oil recovery in both sandstone and carbonate reservoirs.

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