Fluid-fluid Interactions Research Articles

Integrative approach for formation damage diagnosis in a Colombian brownfield: a comprehensive methodology

Formation damage is the reduction of a well's productivity due to the alteration of the permeability of the subsurface rock, leading to economically inefficient operations. This research established a methodology to diagnose such damage, which is divided into: 1) Identification of operational problems, 2) Field sampling and analysis of geological and engineering data, 3) Adaptation of API standards for the study of fluid-fluid and rock-fluid interactions, 4) Identification of damage mechanisms and recommendations. This methodology was applied to two depleted wells in a brown oilfield with reduced productivity to address scale deposition and casing corrosion issues. Finally, the application of control and stimulation fluids must satisfy technical and environmental requirements, with the objective of inducing destabilization of the identified formation damage mechanisms.

A generalized scalar auxiliary variable approach for the Navier–Stokes-[formula omitted]/Navier–Stokes-[formula omitted] equations based on the grad-div stabilization

In this article, based on the grad-div stabilization, we propose a generalized scalar auxiliary variable approach for solving a fluid–fluid interaction problem governed by the Navier–Stokes-ω/Navier–Stokes-ω equations. We adopt the backward Euler scheme and mixed finite element approximation for temporal-spatial discretization, and explicit treatment for the interface terms and nonlinear terms. The proposed scheme is almost unconditionally stable and requires solving only the linear equation with constant coefficient at each time step. It can also penalize for lack of mass conservation and improve the accuracy. Finally, a series of numerical experiments are carried out to illustrate the stability and effectiveness of the proposed scheme.

A molecular simulation study on pore-scale behaviour of nitrogen-based fracking fluids for potential geo-energy applications

Molecular simulations are efficient tools in differentiating individual effects of fluid-fluid interactions and pore-fluid interactions on thermophysical properties of confined fluids; e.g. the molecular packing, adsorption mechanics and availability of accessible pore volume for confined fluids and therefore, indicate the rock fracturing phenomena as a function of geological conditions, fracking fluids nature, its composition and rock mineralogy. Presently, we have deployed the classical GCMC molecular simulations to quantify the adsorption of pure nitrogen and N2–H2O mixture (50%–50% and 30%–70%) inside porous silica rocks. While we found that adsorption and molecular packing of pure nitrogen inside silica slit pores are only a function of pore height, which quantifies the pore-fluid interactions; however, for N2–H2O mixture adsorption and molecular packing of N2 inside silica slit pores has been additionally affected by the water content in the equilibrium bulk mixture that as well describes fluid-fluid interactions inside pores. It is interestingly noted that water in N2–H2O mixture results in water-assisted nitrogen adsorption inside hydrophilic silica slit pores, which has been further proven through the radial distribution function data calculations inside each slit pore. Also, the hydrophilic nature of silica increases water adsorption and hence reduces N2 adsorption inside the smallest pore of H = 20 Å. Such a reduction in N2 adsorption density below its bulk density without layering effect, inside 20 Å pore, further initiates the possibility of negative excess adsorption density.

Nanotube-mediated storage of methane and hydrogen: Insights from molecular simulation

We investigate the storage of methane (CH4) and hydrogen (H2) within single-walled nanotubes carbon, boron nitride (BN), and molybdenum disulfide (MoS2) nanotubes using Grand Canonical Monte Carlo (GCMC) algorithm. We observed that BN nanotubes exhibit the highest weight adsorption capacity for CH4 at 298 K, reaching up to 0.441 g/g at 8 MPa, closely aligning with the Department of Energy (DOE) target of 0.5 g/g. In contrast, MoS2 nanotubes, despite their larger radius, demonstrated the lowest weight adsorption capacity due to their higher atomic mass, with a value of 0.096 g/g at the same pressure. Volumetric adsorption capacity for CH4 was notably highest in (10,10) BN nanotubes, achieving 244 cm3/cm3 at 8 MPa, although this was still below the DOE target of 330 cm3/cm3. For hydrogen storage at 77 K, (30,30) BN nanotubes outperformed the 2025 DOE benchmarks of 5.5 wt% and 0.04 kg/L, with a weight adsorption of 12.19 wt% and a volumetric adsorption of 0.051 kg/L at 8 MPa, respectively. The adsorption heat within nanotubes showed a complex relationship with adsorption quantity, highlighting the interplay between fluid-wall and fluid-fluid interactions. The study also examines the impact of material structure on gas release, revealing a linear relationship between gas release and porosity or pore volume. The Ideal Adsorbed Solution Theory (IAST) was validated for predicting CH4/H2 mixture separations on amorphous carbon materials, and further reveals that the (30,30) BN nanotubes identified as the most suitable candidate for CH4/H2 separation, offering a balance of high CH4 adsorption capacity (20.2 mmol/g) and selectivity of 15 at 8 MPa.

Development and calibration of a bio-geo-reactive transport model for UHS

The increased share of renewable energy sources will lead to large fluctuations in energy availability and increases energy storage’s significance. Large-scale hydrogen storage in the subsurface may become a vital element of a future sustainable energy system because stored hydrogen becomes an energy carrier available on demand. Large hydrogen amounts can be stored in porous formations such as former gas fields or gas storages, while caverns can contribute with high deliverability. However, the storage of hydrogen induces unique processes in fluid-fluid and rock-fluid interactions (for example, bio- and geochemical reactions), which may affect the efficiency of the storage. In the present study, a mathematical model describing the two-phase multicomponent flow in porous media, including bio- and geochemical reactions, is developed to predict these hydrogen-related processes. The proposed model extends an existing model in the open source simulator DuMux describing the bio-reactive transport process considering methanation and sulfate-reduction by geochemical reactions. Significant attention is placed on the reduction from pyrite-to-pyrrhotite coming with the generation of harmful hydrogen sulfide. This reaction is calibrated by developing a kinetic model in DuMux that mimics the observations of reactor experiments from literature. The developed and calibrated model is afterwards used for simulation runs on field scale to assess the impact on Underground Hydrogen Storage (UHS) operations. The developed kinetic model describes the reduction from pyrite-to-pyrrhotite in agreement with the observations in the literature, whereby particular focus was placed on the hydrogen sulfide production rate. The consecutive implementation of the transport model in DuMux on field scale, including the bio- and geochemical reactions, shows the potential permanent hydrogen losses caused by reactions and temporary ones induced by gas-gas mixing with the initial and cushion gas.

Unraveling the Impact of Ethylenediaminetetraacetic Acid Chelating Agents on the Oil Recovery Processes: An Insight into Its Role in Fluid-Fluid and Rock-Fluid Interactions.

In recent years, chelating agents have garnered increasing attention due to their unique capabilities in addressing challenges associated with chemically enhanced oil recovery materials. Most previous studies have primarily focused on examining the influence of chelating agents on rock-fluid interactions. However, their effects on fluid-fluid interactions, specifically on interfacial tension (IFT) characteristics under various conditions, remain relatively unknown. This study investigates the effect of crucial reservoir parameters on the performance of ethylenediaminetetraacetic acid (EDTA) chelating agents in the IFT between crude oil and brine. Furthermore, the study evaluated the impact of varying concentrations of this agent on rock wettability alteration, zeta potential, and spontaneous imbibition. The results illustrated that introducing EDTA at high concentration into seawater (SW) solution reduced the IFT by 85%. Additionally, while higher pH levels contributed to IFT reduction due to increased hydroxyl ions, excessive salinity levels resulted in elevated IFT. Raising the temperature from 30 to 75 °C further decreased the IFT, changing the IFT for optimal EDTA concentration from 20.43 to 2.56 mN/m (∼88% reduction). The changes in zeta potential and contact angle measurements indicated that solutions of 5 and 7 wt % EDTA shifted rock wettability from oil-wet to strongly water-wet, resulting in the wettability alteration index of 1.01 and 1.02, respectively. Inductively coupled plasma analysis, on the other hand, revealed substantial chelation of metal ions from both the solution and rock when EDTA was added to the rock/SW system. This resulted in a significant increase in Ca2+ ions and a decrease in Mg2+ ions, attributed to the multi-ion exchange phenomenon.

Critical behaviour of the contact angle within nonwetting gaps

Recent density functional theory and simulation studies of fluid adsorption near planar walls in systems where the wall–fluid and fluid–fluid interactions have different ranges, have shown that critical point wetting may not occur and instead nonwetting gaps appear in the surface phase diagram, separating lines of wetting and drying transitions, that extend up to the critical temperature Tc . Here we clarify the features of the surface phase diagrams that are common, regardless of the range and balance of the forces, showing, in particular, that the lines of temperature driven wetting and drying transitions, as well as lines of constant contact angle π>θ>0 , always converge to an ordinary surface phase transition at Tc . When nonwetting gaps appear the contact angle either vanishes or tends to π as t≡(Tc−T)/Tc→0 . More specifically, when the wall–fluid interaction is long-ranged (dispersion-like) and the fluid–fluid short-ranged we estimate π−θ∝t0.16 , compared with θ∝t0.77 when the wall–fluid interaction is short-ranged and the fluid–fluid dispersion-like, allowing for the effects of bulk critical fluctuations. The universal convergence of the lines of constant contact angle implies that critical point filling always occurs for fluids adsorbed in wedges.

The use of biological catalyst (enzyme) for enhanced oil recovery in Niger Delta

This study is aimed at using bio-catalyst (enzymes) for enhanced oil recovery in Niger Delta. Three different enzymes produced from microbial isolates with code ID; LPE1, LPE2 and AME were use in analyzing enzymes effect on the rock-fluid and fluid-fluid interaction test to simulate the conditions in the reservoir. The tests carried out include; wettability, interfacial tension (IFT) and adhesion test. The results from these tests show that addition of enzymes to rock-fluid interface has the potential of enhancing recovery of crude oil. From the result, the use of enzyme caused an alteration in the wettability of the rock from oil-wet to water-wet with a 33° difference. The selected enzyme LPE1 showed a significant difference in reduction of interfacial tension by a factor of 4, while LPE2 and AME did not show any significant difference. In conclusion, the wettability and IFT tests results were the basis for choosing LPE1 for core flooding process. Enzyme (LPE1) flooding after waterflood was able to give an additional 11.5 % oil recovery. From the results, the percentage recovery is a pointer to the fact that when the primary and secondary oil recovery methods are no longer viable in terms of economics, the Enyme enhanced oil recovery is the best method of mobilizing trapped crude oil in the Secondly, there is no negative effect on the crude oil quality using the enzyme-EOR because the enzymes only increase the rate of the chemical reaction on the rock media without undergoing any permanent chemical change.

Flow Simulation of Fluid Under Pressure, Through Pipes for Oil and Gas Transport

The work presents a simulation of the flow of liquids under pressure, through pipelines intended for the transport of oil and natural gas. The simulation was done using the SOLIDWORKS program. Computational Fluid Dynamics (CFD) simulation facilitates the analysis of complex fluid flow problems involving liquid-gas, fluid-solid, or fluid-fluid interactions. CFD allows us to design products and systems that meet fluid flow and heat transfer requirements.

A brief juxtaposition of the effects of combining rules on acid gas geosequestration at a constant temperature

Acid gases are hazardous to humanity, industries, the environment, and climate at large and their effects must be blunted as a matter of some urgency in mass-producing fields such as oil and gas for operations to be safely conducted. Diverse means of removal and safe storage exist, for which injecting these acid gases into geological formations (geosequestration) is an attractive one due to its economic viability and environmental friendliness. Some of these geological storage choices include depleted hydrocarbon reservoirs and deep saline aquifers. However, many interactions are in play during geosequestration and the one of interest in this work is the fluid-fluid interaction between the formation fluid (water) and injected fluid (acid gas). Various parameters are key to determining the safety, security, and containment of the injected plume to forestall leakage. Some of these parameters are interfacial tension, absorption, and dissolution of the injected fluid into the bulk water and adsorption of the injected fluid onto the interface of the formation water. Due to the extreme pressure and temperature circumstances, parameters may be hard to secure directly from the reservoir. Therefore, an indirect but reliable method of procuring these important parameters is required. Molecular dynamics offers a mechanism to model reservoir conditions and gain invaluable insight into the nature of interactions between the fluids involved. The modelling of molecular fluids can vary considerably depending upon several factors. Pairwise combining rules is one such factor, and in acid gas geosequestration, however, the influence of the effect of combining rules in the modelling of these fluids has garnered little attention thus far. In this work, we investigated the impact of three of the most common combining rules – Lorentz-Berthelot (arithmetic), geometric and the sixth power – and compared to available experimental data. We found that while some of the parameters compared showed only marginal statistical dissimilarities such as interfacial tension and radial distribution function, on an important front such as density both arithmetic and geometric mixing rules provided results closer to the experimental data. For simple molecules, we conclude, arithmetic and geometric mixing rules should suffice, insofar as the modelling is not for rare gases.

Pore-scale study of the effects of DTPA chelating agent flooding on oil recovery utilizing a clay-coated micromodel

The use of diethylenetriaminepentaacetic acid (DTPA) chelating agent has shown promising results for enhanced oil recovery (EOR) in prior research. Several mechanisms, mainly resulting from rock-fluid interaction, have been proposed for chelating agent flooding; however, little attention has been paid to fluid-fluid interaction thus far. The assessment of these mechanisms has primarily relied on macroscopic techniques such as core flooding. This paper aims to investigate the injection of DTPA brine and its dominant mechanisms at the pore scale using a clay-coated micromodel. The micromodel tests were performed under oil-wet and water-wet states. For a more precise examination of fluid/fluid interactions, the dynamic interfacial tension (IFT) and Zeta potential were measured. It was observed that the injection of DTPA brine in water-wet state changed the saturation distribution and increased oil recovery. Based on visual inspections, this change in saturation distribution could potentially be linked to the formation of micro-dispersions and viscoelastic interfacial phenomena. Micro-dispersions facilitate flow to unswept areas, and viscoelastic interface formation reshapes the interface between oil and brine, causing disconnected oil droplets to coalesce and thus increase recovery. Under the oil-wet state, the micro-dispersion formation and wettability alteration can be the dominant mechanisms, and the amount of recovered oil was higher than that observed in the water-wet state. Furthermore, Zeta potential measurements at the interface between brine and oil showed a more negative value for DTPA brine, which is effective in wettability alteration and micro-dispersions stability. The results indicate that IFT reduction was not significant enough to be considered the dominant mechanism, although it assists in DTPA brine penetration into the crude oil and subsequent micro-dispersion formation.

Effective Relative Permeabilities Based on Momentum Equations with Brinkman Terms and Viscous Coupling

Summary The relative permeability expresses the mobility reduction factor when a fluid flows through a porous medium in the presence of another fluid and appears in Darcy’s law for multiphase flow. In this work, we replace Darcy’s law with more general momentum equations accounting for fluid-rock interaction (flow resistance), fluid-fluid interaction (drag), and Brinkman terms responding to gradients in fluid interstitial velocities. By coupling the momentum equations with phase transport equations, we study two important flow processes—forced imbibition (coreflooding) and countercurrent spontaneous imbibition. In the former, a constant water injection rate is applied and capillary forces are neglected, while in the latter, capillary forces drive the process and the total flux is zero. Our aim is to understand what relative permeabilities result from these systems and flow configurations. From previous work, when using momentum equations without Brinkman terms, unique saturation-dependent relative permeabilities are obtained for the two flow modes that depend on the flow mode. Now, with Brinkman terms included, the relative permeabilities depend on local spatial derivatives of interstitial velocity and pressure. Local relative permeabilities are calculated for both phases utilizing the ratio of phase Darcy velocity and phase pressure gradient. In addition, we use the Johnson-Bossler-Naumann (JBN) method for forced imbibition (with data simulated under the assumption of negligible capillary end effects) to calculate interpreted relative permeabilities from pressure drop and average saturation. Both flow setups are parameterized with literature data, and sensitivity analysis is performed. During coreflooding, Brinkman terms give a flatter saturation profile and higher front saturation. The saturation profile shape changes with time. Local water relative permeabilities are reduced, while they are slightly raised for oil. The saturation range where relative permeabilities can be evaluated locally is raised and made narrower with increased Brinkman terms. JBN relative permeabilities deviate from the local values: The trends in curves and saturation range are the same but more pronounced as they incorporate average measurements, including the strong impact at the inlet. Brinkman effects vanish after sufficient distance traveled, resulting in the unique saturation functions as a limit. Unsteady state (USS) relative permeabilities (based on transient data from single-phase injection) differ from steady-state (SS) relative permeabilities (based on SS data from coinjection of two fluids) because the Brinkman terms are zero at SS. During spontaneous imbibition, the higher effect from the Brinkman terms caused oil relative permeabilities to decrease at low water saturations and slightly increase at high saturations, while water relative permeability was only slightly reduced. The net effect was a delay in the imbibition profile. Local relative permeabilities approached the unique saturation functions without Brinkman terms deeper in the system because phase velocities (involved in the Brinkman terms) decreased with distance. In both systems, scaling and simulations demonstrate that the relative change in relative permeabilities due to Brinkman terms increases with the Brinkman coefficient, permeability, and inverse squared distance from the inlet.

Fluid-fluid interfacial properties during low salinity waterflooding

Understanding the fluid–fluid interfacial interactions is critical to enhancing oil recovery, underground CO2 storage, and soil remediation. Fluid-fluid interfacial interactions were identified as key parameters to govern fluid–fluid interfacial properties. In this investigation, we aim to evaluate the properties of the oil-brine interface in function of fluid compositions during low salinity waterflooding (LSW). Specifically, the main target is to unravel the oil-brine structure, including orientation of the carboxylic group (–COOH), interfacial structure, and species distribution. We utilized molecular dynamics (MD) simulation to evaluate the species distribution and surface structure at the molecular scale. The MD results showed that the carboxylic group accumulated near the oil-brine interface. The orientation of C=O in the carboxylic group is closer to 90° in the brines with all salinity ranges, which is perpendicular to the oil-brine interface. The accumulation and orientation of the carboxylic group is, however, not sensitive to salinity variations. Furthermore, the oil-brine interfacial area turns to be wider with lowering salinity. Radial distribution function (RDF, g(r)) confirmed that lowering salinity decreases g(r) between –COOH and water and thus looses the affinity of oil to water. This investigation provides insights into the fluid–fluid interfacial properties of LSW at the molecular level.

Microscopic and macroscopic assessment of carbonate dissolution for geologic {{hbox {CO}}_{2}} storage

Carbon capture and storage in underground formations might be considered as a relevant technology to curb anthropogenic climate gas emissions. However, carbon dioxide ({{hbox {CO}}_{2}}) injection can lead to severe rock-fluid interactions depending on the thermodynamic conditions, rock and fluids composition. The progressive dissolution of {{hbox {CO}}_{2}} in the formation brine results in mineral dissolution/precipitation processes that may drastically change the properties of the reservoir. This study is an attempt to get a deeper understanding of the dissolution/precipitation processes in a heterogeneous limestone at microscopic and macroscopic levels by a synergy between Isothermal Titration Calorimetry (ITC) and core flooding experiments with in-situ imaging to quantify uneven displacement fronts and understand the influence of reactions on a larger scale. Rock-fluid and fluid-fluid interactions, evaluated by ITC experiments, indicate that the carbonate dissolution is unfavorable with respect to enthalpy change but thermodynamically favorable with respect to entropy change (cations and hydrogen carbonate increase in the brine). Core flooding experiments with in-situ imaging by PET/CT show that complex pore structures cause a variation in the availability and ratio of the reactive fluid throughout the porous medium, hence, non-uniform dissolution was confirmed at core scale. The synergy between microcalorimetry and core flooding provides relevant insights into the dissolution of heterogeneous carbonate rocks at both microscopic and macroscopic scales.

Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks Based on X-Ray Microfocus Radiography

Summary An uncommon facet of formation evaluation is the assessment of flow-related in-situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow in complex rocks, i.e., saturation-dependent capillary pressure and relative permeability. Furthermore, these two crucial properties are usually measured independently. Capillary pressure is typically assessed using static measurements and unrealistic pressure conditions, whereas relative permeability is evaluated dynamically. Consequently, the disparity between the nature of the two experimental procedures often results in a potentially significant loss of information. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks which allow for the simultaneous and dynamic evaluation of two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasicontinuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. The experimental results indicate that flow patterns and in-situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement approaches piston-like behavior. The assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles resulting from fluid displacement. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high-permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.

Molecular perspectives of interfacial properties of the hydrogen+water mixture in contact with silica or kerogen

Interfacial behaviours in multiphase systems containing H2 are crucial to underground H2 storage but are not well understood. Molecular dynamics simulations were carried out to investigate interfacial properties of the H2+H2O and H2+H2O+silica/kerogen systems over a broad range of temperatures (298 - 523 K) and pressures (1 - 160 MPa). The combination of the H2 model with the INTERFACE force field and TIP4P/2005 H2O model can accurately predict the experimental interfacial tensions (IFTs) of the H2+H2O mixture. The IFTs from simulations are also in accordance with predictions from density gradient theory combined with the PC-SAFT equation of state. In general, the IFT decreases with pressure and temperature. However, at relatively high temperatures and pressures, the IFTs increase with pressure. The opposite pressure influence on IFTs can be explained by the inversion of the sign of the relative adsorption of H2. The H2 enrichment in the interfacial regions was identified in density distributions. Meanwhile, the behaviours of contact angles (CAs) in the H2+H2O+silica system are noticeably different from those in the H2+H2O+kerogen system. The H2O CAs for the H2+H2O+silica and H2+H2O+kerogen systems increase with pressure and decrease with temperature. However, the influence of temperature and pressure on these CAs is less pronounced for the H2+H2O+silica system at low temperatures. The behaviours of CAs were understood based on the variations of IFTs in the H2+H2O system (fluid-fluid interaction) and adhesion tensions (fluid-solid interaction). Furthermore, the analysis of the atomic density distributions indicates that the presence of H2 in between the H2O and the silica/kerogen is almost negligible. Nevertheless, the adsorption of H2O on the silica outside the H2O is strong, while less H2O adsorption is seen on the kerogen.

Role of sulfate ion on wettability alteration and oil mobilization in chalk reservoirs during modified salinity waterflooding

It has often been reported that an increase in sulfate has a positive effect on altering wettability and mobilizing oil during modified salinity water flooding in carbonate reservoirs. However, this understanding is mostly based on experimental studies using outcrop rock material. Therefore, this study aims to reassess the role of sulfate on altering wettability and recovery performance during modified salinity water injection in oil-saturated porous media of chalk reservoirs using real reservoir material. We compare the results with outcrop samples to evaluate the effects of sulfate and rock material on wettability alteration and oil mobilization. We conduct dynamic contact angle measurements and coreflooding experiments in reservoir conditions. Our findings contradict the previous observations, as we discovered that decreasing the sulfate concentration in the displacing fluid causes a shift in the reservoir chalk's wettability to a more water-wet condition, which significantly improves oil mobilization. We also establish that outcrop chalk samples, typically used in laboratory experiments, cannot be used as reliable analogues for reservoir chalk samples with the same geological age. Finally, we use direct pore scale simulations to demonstrate the impact of observed wettability alteration on oil mobilization. Our simulation results align with our experimental findings, indicating that wettability alteration is the primary mechanism in our experiments, as fluid-fluid interactions were ignored, and flow was mainly controlled by the medium's wettability state.

An experimental approach to investigate oil recovery during ion-tuned water injection: A new insight into the asphaltene effect

Regarding the increase of the worldwide demand for supplying fuel, Enhanced Oil Recovery (EOR) methods, as promising methods for increasing oil recover factor, is a vital issue. The smart water injection is a well-accepted as an environmentally friendly, inexpensive, and efficient EOR method. This research aims to investigate the effect of oil and asphaltene chemistry on the sensitivity of oil production toward ion-tuned water. In this regard, three oil samples of crude oil, deasphaltened oil, and asphaltene-rich toluene were employed, as well as various brine samples containing different salinity values and ion types. The provided oil samples were characterized using Fourier-transform infrared spectroscopy (FTIR) and elemental analysis. The interfacial tension (IFT) values between the prepared water and oil samples of crude oil, deasphaltened oil, and asphaltene-rich toluene was in the ranges of 7.5–11, 14–23, and 12–19 m.N/m, respectively. Regarding higher IFT between the sulfate-rich water and asphaltene-rich oil, it was shown that the asphaltene molecules have a lower affinity toward the sulfate ions. In contrast, enriching the seawater with magnesium and calcium ions led to a tense IFT reduction. Regarding the contact angle measurements, the wettability of the sections, which were aged by the asphaltene-rich toluene, was respectively less sensitive to the ion-tuned waters compared with those aged by deasphaltened oil. For instance, because of the seawater treatment, the contact angles of the sections lie in the ranges of 48–87, 45–83, and 56–98° for sections aged by crude oil, deasphaltened oil, and asphaltene-rich toluene, respectively. More feasibility of the calcium and magnesium for desorption of the hydrocarbons was also observed in the zeta potential tests. The overall effects of rock-fluid and fluid-fluid interactions were observed in the imbibition tests. While the production from the crude oil saturated due to imbibition of the magnesium and calcium was noticeable, lower production was observed due to the sulfate-rich water imbibition into the asphaltenic oil sample. The experimental approach in this study could be a benchmark to screen the suitable reservoir oil for water injection.

Quantification of the impact of pore pressure on relative permeability curves utilizing coreflood unit with gamma ray scanning capability

Physics of multiphase flow in porous media at Darcy scale heavily relies on the concept of relative permeability. Moreover, relative permeability is an important input parameter for numerical reservoir simulation for multiphase flow in porous media. Often fixed set of relative permeability curves is applied for the entire complex large-scale reservoir models whilst the pressure typically declines during a field’s production. In this study, we are experimentally focusing on investigating the effect of high pressures on relative permeability curves.We use a state-of-the-art custom-made relative permeability steady-state flow system with integrated gamma-ray scanning. We limit the fluids to a model oil, brine, and rock to avoid any secondary effects of fluid-rock interactions, such as wettability alteration, asphaltenes, and gas-dissolution, miscibility, and interaction of phase behavior and flow. We run the relative permeability scans at a fixed temperature (isotherm) and at several pore pressure values (isobars), such as 2000, 4000, 6000, and 8000 psi with fixed and variable net confining pressures. To be able to perform the analysis more diligently, we observe the in-situ phase saturations via two methods: mass balance and gamma-ray scanning. The resulting relative permeability curves are then compared to each other to examine the impact of pressure. We did not observe significant pressure effect on relative permeability measurements in simple model system used in this work, where minimal fluid-fluid and fluid-rock interactions occur. However, the outcome of this work should not be extended to more complex systems where strong fluid-fluid and rock-fluid interactions take place, such as gas flooding with strong solubility effects, and chemical flooding.Systematic analysis of the pressure effect on relative permeability is extremely scarce in the literature, even though the pressure varies significantly in the reservoir during the lifetime of the field. Therefore, it is essential to understand pressure effect on relative permeability under well controlled laboratory conditions. The outcomes of this paper may help engineers to improve their model predictions during field development and therefore decision-making processes.

Fluid-Fluid Interaction Problems at High Reynolds Numbers: Reducing the Modeling Error with LES-C

We consider a fluid-fluid interaction problem, where two flows (with high Reynolds numbers for one or both of these flows) are coupled through a joint interface. A nonlinear coupling equation, known as the rigid lid condition, creates an extra level of difficulty, typical for atmosphere-ocean problems. We propose a novel turbulence model, NS- -C, from the recently introduced family of LES-C (large eddy simulation with correction) models. Combining it with the so-called geometric averaging (GA) partitioning method, we obtain the NS- -C-GA model that is shown to possess several key properties. First, the preexisting solvers for the subdomains can be used, which is critical, e.g., for atmosphere-ocean applications. Second, the LES-C turbulence models use defect correction to efficiently reduce the modeling error of the corresponding LES models; we demonstrate numerically that the NS- -C model outperforms its LES counterpart, the NS- model. It has also been shown recently that it is favorable for an LES model to have the nonfiltered velocity in the interface terms. The NS- -C-GA model possesses this important property; we also show it to be stable and have optimal convergence properties.