scholarly journals In Situ Wettability Investigation of Aging of Sandstone Surface in Alkane via X-ray Microtomography

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5594
Author(s):  
Nilesh Kumar Jha ◽  
Maxim Lebedev ◽  
Stefan Iglauer ◽  
Jitendra S. Sangwai ◽  
Mohammad Sarmadivaleh
Keyword(s):  
Contact Angles ◽  
Wettability Alteration ◽  
Experimental Investigations ◽  
Rock Surface ◽  
Phase System ◽  
Intermediate Water ◽  
Single Plane ◽  
X Ray ◽  
Sandstone Rock

Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the sandstone rock surface to a weakly water wetting state on aging by alkanes using induced polarization at the interface. The study adds to the understanding of initial wettability conditions as well as the oil migration process of the paraffinic oil-bearing sandstone reservoirs. Further, it complements the knowledge of the wettability alteration of the rock surface due to chemisorption, usually done by nonrepresentative technique of silanization of rock surface in experimental investigations.

scholarly journals Parametric Investigation of Wettability Alteration of Reservoir Rocks by Asphaltene Deposition: Experimental and Modeling Approaches

2020 ◽  
Vol 4 (1) ◽  
pp. 1-8
Author(s):  
Khodapanah E
Keyword(s):  
Contact Angle ◽  
Pso Algorithm ◽  
Contact Angles ◽  
Phase Changes ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Inference System ◽  
Sandstone Rock

Rock wettability plays an important role in water flooding process as it controls fluid flow, oil recovery and distribution of residual oil in any oil reservoir. In this context, polar oil components such as asphaltene contents may adsorb onto the pore mineral surfaces and alter wettability of the reservoir rock. Due to this importance, this study aims to investigate the effects of different parameters such as concentration of asphaltene, salinity, temperature and time on the rock wettability alteration process. For this purpose, dynamic contact angle measurement was performed. The results showed that the increment of asphaltene concentration in the oleic phase changes the wettability of water-wet sandstone rock to oil-wet condition; the increase in the concentration of asphaltene fraction from 0.1 to 5.0 g/lit increased the contact angle from 0 to 97 degrees. In addition, the increase in the brine salinity from 500 to 8000 ppm increased the ability of asphaltene to adsorb on the rock surface and consequently, increased oil wetness; the equivalent contact angle changed from 0 to 113 degree for 5 g/lit asphaltene content after 192 hours. Moreover, the results illustrated that a rise in temperature from 40 to 70 o C accelerates adsorption of asphaltene, but it has not significant effect on the final contact angle. Furthermore, the Adaptive Neuro-Fuzzy Inference System (ANFIS) is incorporated into the Particle Swarm Optimization (PSO) algorithm to correlate contact angle with the aforementioned parameters. To this end, the obtained experimental data are used to train and test the algorithm. The outputs of ANFIS-PSO algorithm are compared with the measured contact angles in both graphical and statistical manners. The training and testing determination coefficients (R 2 ) have been obtained as 0.99091 and 0.98761, respectively. The analysis indicates that the predictive model can be used with a high degree of confidence to investigate the effect of different parameters on wettability alteration

Dynamics of Low-Interfacial-Tension Imbibition in Oil-Wet Carbonates

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1092-1107 ◽  
Author(s):  
M.. Tagavifar ◽  
M.. Balhoff ◽  
K.. Mohanty ◽  
G. A. Pope
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Flow Behavior ◽  
Contact Angles ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Surface Phenomenon ◽  
Rock Surface ◽  
The Core ◽  
Aspect Ratios

Summary Surfactants induce spontaneous imbibition of water into oil-wet porous media by wettability alteration and interfacial-tension (IFT) reduction. Although the dependence of imbibition on wettability alteration is well-understood, the role of IFT is not as clear. This is partly because, at low IFT values, most water/oil/amphiphile(s) mixtures form emulsions and/or microemulsions, suggesting that the imbibition is accompanied by a phase change, which has been neglected or incorrectly accounted for in previous studies. In this paper, spontaneous displacement of oil from oil-wet porous media by microemulsion-forming surfactants is investigated through simulations and the results are compared with existing experimental data for low-permeability cores with different aspect ratios and permeabilities. Microemulsion viscosity and oil contact angles, with and without surfactant, were measured to better initialize and constrain the simulation model. Results show that with such processes, the imbibition rate and the oil recovery scale differently with core dimensions. Specifically, the rate of imbibition is faster in cores with larger diameter and height, but the recovery factor is smaller when the core aspect ratio deviates considerably from unity. With regard to the mechanism of water uptake, our results suggest, for the first time, that (i) microemulsion formation (i.e., fluid/fluid interface phenomenon) is fast and favored over the wettability alteration (i.e., rock-surface phenomenon) in short times; (ii) a complete wettability transition from an oil-wet to a mixed microemulsion-wet and surfactant-wet state always occurs at ultralow IFT; (iii) wettability alteration causes a more uniform imbibition profile along the core but creates a more diffused imbibition front; and (iv) total emulsification is a strong assumption and fails to describe the dynamics and the scaling of imbibition. Wettability alteration affects the imbibition dynamics locally by changing the composition path, and at a distance by changing the flow behavior. Simulations predict that even though water is not initially present, it forms inside the core. The implications of these results for optimizing the design of low-IFT imbibition are discussed.

In-Situ Visualization of Multidimensional Imbibition in Dual-Porosity Carbonates

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1631-1642 ◽  
Author(s):  
Amar J. Alshehri ◽  
Anthony R. Kovscek
Keyword(s):  
Oil Recovery ◽  
Experimental Results ◽  
Wettability Alteration ◽  
X Ray ◽  
Surfactant Solutions ◽  
Phase Saturation ◽  
Gravity Effects ◽  
The Matrix ◽  
Ultralow Ift

Summary Oil recovery by waterflood is usually small in fractured carbonates because of selective channeling of injected water through fractures toward producers, leaving much of the oil trapped in the matrix. One option to mitigate the low recovery is to reduce fracture uptake by increasing the viscosity of the injected fluids by use of polymers or foams. Another option, that is the objective of this work, is to inject surfactant solutions to reduce capillary effects responsible for trapping oil and allow gravity to segregate oil by buoyancy. Analysis of gravity and capillary forces suggests that such segregation is achievable in the laboratory, provided that cores are moderately long and oriented vertically. Besides investigating the role of gravity on oil recovery, the effect of surfactant-flood mode (secondary-flood mode and tertiary-flood mode) on the ultimate recovery (UR) was also investigated. To investigate the predictions of this analysis, coreflood experiments were conducted by use of carbonate cores and monitored by an X-ray computed-tomography (CT) scanner featuring true vertical positioning to quantify fluid saturation history in situ. Novel aspects of this work include cores that are oriented both horizontally and vertically to maximize gravitational effects as well as a special core holder that mimics aspects of fractured systems by use of the whole core. This paper discusses the contrast in experimental results in vertical and horizontal orientation with and without surfactant. To study gravity effects, surfactant reduced interfacial tension (IFT) from 40 to 3 mN/m. For this mode of recovery, ultralow IFT is not preferred because some capillary action is needed to aid injectant transport into the matrix. The vertical experiment showed that gravity has the potential of improving oil recovery at low IFT. Another surfactant was used to study the flood-mode effect; this surfactant reduced IFT from 40 to 0.001 mN/m (ultralow IFT). In this study, two experiments were conducted: a tertiary-surfactant-flood experiment and a secondary-surfactant-flood experiment. The secondary-flood experiment showed an improvement in recovery with the early implementation of the surfactant flood relative to the tertiary-flood experiment. This work highlights the importance of gravity at low IFT in terms of mobilizing trapped oil and also the effect of flood mode on UR. Moreover, this work emphasizes the use of surfactant solutions as a method of enhancing oil recovery in fractured resources not necessarily because of wettability alteration but mainly because of gravity effects. Experimental results are presented primarily as 1D and 3D reconstructions of in-situ oil- and water-phase saturation obtained by use of X-ray CT.

Equation of State for Relative Permeability, Including Hysteresis and Wettability Alteration

SPE Journal ◽  
2017 ◽  
Vol 22 (06) ◽  
pp. 1915-1928 ◽  
Author(s):  
Saeid Khorsandi ◽  
Liwei Li ◽  
Russell T. Johns
Keyword(s):  
Experimental Data ◽  
Equation Of State ◽  
Surface Properties ◽  
Relative Permeability ◽  
Contact Angles ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Relative Permeabilities ◽  
Tuning Parameters ◽  
Rock Structure

Summary Commercial compositional simulators commonly apply correlations or empirical relations that are based on fitting experimental data to calculate phase relative permeabilities. These relations cannot adequately capture the effects of hysteresis, fluid compositional variations, and rock-wettability alteration. Furthermore, these relations require phases to be labeled, which is not accurate for complex miscible or near-miscible displacements with multiple hydrocarbon phases. Therefore, these relations can be discontinuous for compositional processes, causing inaccuracies and numerical problems in simulation. This paper develops for the first time an equation-of-state (EOS) to model robustly and continuously the relative permeability as a function of phase saturations and distributions, fluid compositions, rock-surface properties, and rock structure. Phases are not labeled; instead, the phases in each gridblock are ordered on the basis of their compositional similarity. Phase compositions and rock-surface properties are used to calculate wettability and contact angles. The model is tuned to measured two-phase relative permeability curves with very few tuning parameters and then is used to predict relative permeability away from the measured experimental data. The model is applicable to all flow in porous-media processes, but is especially important for low-salinity polymer, surfactant, miscible gas, and water-alternating-gas (WAG) flooding. The results show excellent ability to match measured data, and to predict observed trends in hysteresis and oil-saturation trapping, including those from Land's model and for a wide range in wettability. The results also show that relative permeabilities are continuous at critical points and yield a physically correct numerical solution when incorporated within a compositional simulator (PennSim 2013). The model has very few tuning parameters, and the parameters are directly related to physical properties of rock and fluid, which can be measured. The new model also offers the potential for incorporating results from computed-tomography (CT) scans and pore-network models to determine some input parameters for the new EOS.

The Use of Advanced Analytical Techniques for Characterization of the Chemical, Physical, and Crystallographic Nature of a Surface

1973 ◽  
Vol 31 ◽  
pp. 132-133 ◽  
Author(s):  
R. E. Herfert
Keyword(s):  
Surface Characterization ◽  
Analytical Techniques ◽  
X Ray Diffraction ◽  
Depth Of Penetration ◽  
X Ray ◽  
The Past ◽  
Transmission Electron ◽  
Scanning Electron

Studies of the nature of a surface, either metallic or nonmetallic, in the past, have been limited to the instrumentation available for these measurements. In the past, optical microscopy, replica transmission electron microscopy, electron or X-ray diffraction and optical or X-ray spectroscopy have provided the means of surface characterization. Actually, some of these techniques are not purely surface; the depth of penetration may be a few thousands of an inch. Within the last five years, instrumentation has been made available which now makes it practical for use to study the outer few 100A of layers and characterize it completely from a chemical, physical, and crystallographic standpoint. The scanning electron microscope (SEM) provides a means of viewing the surface of a material in situ to magnifications as high as 250,000X.

In Situ X-Ray Absorption Studies of the Electrochemical Reduction of Hydroxocobalamin

1997 ◽  
Vol 7 (C2) ◽  
pp. C2-619-C2-620 ◽  
Author(s):  
M. Giorgett ◽  
I. Ascone ◽  
M. Berrettoni ◽  
S. Zamponi ◽  
R. Marassi
Keyword(s):  
Electrochemical Reduction ◽  
X Ray ◽  
Absorption Studies ◽  
X Ray Absorption

A Revised O2 Reduction Model in Li-O2 Batteries as Revealed by in Situ Small Angle X-Ray Scattering

2019 ◽  
Author(s):  
Christian Prehal ◽  
Aleksej Samojlov ◽  
Manfred Nachtnebel ◽  
Manfred Kriechbaum ◽  
Heinz Amenitsch ◽  
...  
Keyword(s):  
Small Angle ◽  
Wide Angle ◽  
Reduction Mechanism ◽  
Reduction Model ◽  
X Ray ◽  
X Ray Scattering ◽  
O2 Reduction ◽  
Ray Scattering

<b>Here we use in situ small and wide angle X-ray scattering to elucidate unexpected mechanistic insights of the O2 reduction mechanism in Li-O2 batteries.<br></b>

Single Crystal Growth of High-Pressure Phases of Ice and Salt Hydrate Far Below the Original Melting Point by Mixing Alcohol: Crystal Structure Determination of Magnesium Chloride Heptahydrate

2020 ◽  
Author(s):  
Keishiro Yamashita ◽  
Kazuki Komatsu ◽  
Hiroyuki Kagi
Keyword(s):  
Crystal Structure ◽  
High Pressure ◽  
Crystal Growth ◽  
Single Crystal ◽  
Room Temperature ◽  
Growth Technique ◽  
Salt Hydrate ◽  
X Ray

An crystal-growth technique for single crystal x-ray structure analysis of high-pressure forms of hydrogen-bonded crystals is proposed. We used alcohol mixture (methanol: ethanol = 4:1 in volumetric ratio), which is a widely used pressure transmitting medium, inhibiting the nucleation and growth of unwanted crystals. In this paper, two kinds of single crystals which have not been obtained using a conventional experimental technique were obtained using this technique: ice VI at 1.99 GPa and MgCl<sub>2</sub>·7H<sub>2</sub>O at 2.50 GPa at room temperature. Here we first report the crystal structure of MgCl2·7H2O. This technique simultaneously meets the requirement of hydrostaticity for high-pressure experiments and has feasibility for further in-situ measurements.

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