Oil Displacement Process Research Articles

Oil Displacement from a Porous Medium with the Aid of a Graphite Suspension

It has been found that N aqueous suspension of planar graphite nanoparticles exhibits properties of displacement fluid at the oil–water interface. Experiments with the Hele–Shaw cell showed that the process of oil displacement from the interface is not accompanied by the formation of viscous “fingers” as a result of development of instability at the oil–water interface.

Вытеснение нефти из пористой среды с использованием графитовой суспензии

AbstractIt has been found that N aqueous suspension of planar graphite nanoparticles exhibits properties of displacement fluid at the oil–water interface. Experiments with the Hele–Shaw cell showed that the process of oil displacement from the interface is not accompanied by the formation of viscous “fingers” as a result of development of instability at the oil–water interface.

Study on Dynamic Characteristics of Microbial Enhanced Oil Recovery

With the rapid development of economy, the demand for oil is increasing day by day. MEOR has the advantages of low cost and no pollution to the environment, attracted widespread attention. In this paper, the dynamic characteristics of microbial enhanced oil recovery were studied by laboratory experiments. The result showed that all the microbial flooding recovery rate could reach more than 5%, and the total recovery could reach more than 35% and if the injection period of microbial composite system was advanced, the whole oil displacement process could be shortened and the workload would be reduced.

IMPROVEMENT OF HYDROCHLORIC ACID FORMATION TREATMENT FOR VOLGO-URALS CARBONATES

Background. At the present stage of development of the oil and gas industry, the structure of oil reserves in the Republic of Bashkortostan is deteriorating. The share of hard-to-recover oil reserves, including those associated with carbonate reservoirs, is increasing. More than 2 0 % of residual and hard-to-recover oil reserves of Bashkortostan are found in carbonate reservoirs. Productive deposits containing oil deposits have a complex geological structure. The development of these reserves will allow maintaining the current level of hydrocarbon production for a long time. The use of hydrochloric acid carbonate reservoirs treatment allows to increase the efficiency of exploitation of these deposits. However, oil deposits in carbonate reservoirs are often operated with an ineffective water flooding system or on a natural regime, which leads to a decrease in reservoir pressure in the bottomhole zone of producing wells. The use of standard hydrochloric acid treatment of production wells under these conditions proves ineffective. In this regard, studies have been conducted aimed at increasing the effectiveness of measures to intensify oil production, which, of course, is an urgent task. Aims and Objectives. Improvement of the hydrochloric acid treatment for Volga-Ural carbonate reservoirs in conditions of low reservoir pressure to increase the efficiency of the method of stimulation of the inflow to the wells. Metods. The mechanism of action of the acid solution on the productive reservoir is based on analytical methods of research. Determination of the rate of reaction of acid solutions with carbonate rock using reaction moderators and reagents is based on a generalization of the results of laboratory studies. Commercial types of research were used in experimental-industrial tests of the proposed method of hydrochloric acid exposure. The results of field work on the intensification of the inflow to production wells were processed using analytical and mathematical methods. Rezults. Based on the concept of the mechanism of the process of oil displacement from weakly permeable carbonate reservoirs, methods for treating the bottomhole zone of producing wells, including those for low reservoir pressure, are proposed. The results of the implementation of the proposed method made it possible to increase the production rate by more than 2 times in comparison with the treatment performed by traditional technology, and the duration of the effect from treatment was much larger. Conclusion. The application of the proposed methods of hydrochloric acid treatment during the intensification of the influx from the carbonate layers of the Bashkir and Vereiskian, Tournaisian stages, including for the conditions of low reservoir pressure in the Republic of Bashkortostan oil fields, will significantly improve the efficiency of the work.

A Magnetic Resonance Study of Low Salinity Waterflooding for Enhanced Oil Recovery

Low salinity waterflooding (LSF) has been proposed to improve oil recovery, with major projects in progress worldwide. There is however no consensus on the mechanisms of LSF for enhanced oil recovery (EOR). Wettability change is the most widely accepted mechanism. In this work, magnetic resonance (MR) and magnetic resonance imaging (MRI) were employed to monitor oil displacement processes during model laboratory scale LSF experiments. The MR and MRI measurements permit evaluation of putative LSF mechanisms. Two clay-coated sand packs, one with nonswelling kaolinite, the other with swelling montmorillonite, were prepared as model porous media for LSF. The interactions between pore fluids (oil and water) and the clay-coated pore surfaces were evaluated with relaxation time measurements. A MRI methodology, spin echo single point imaging (SE-SPI), was employed to spatially resolve the T2 distribution along the sand pack. The oil saturation profiles were determined from SE-SPI measurements. A new differential relaxation time distribution method is proposed in this work for oil saturation estimation. The pore fluid self-diffusion coefficients were measured. The mechanism of wettability change for LSF is suggested on the basis of the oil diffusion coefficient variation with LSF. The similarities and differences between the kaolinite and montmorillonite behaviors are discussed. This work demonstrates that MR and MRI are robust tools to monitor oil displacement processes, with the potential to reveal the mechanisms of LSF and other procedures for enhanced oil recovery.

Physical modeling of ultraviscous oil displacement by using solvent on a large model of oil reservoir

As a result of a series of experiments for the physical modeling of oil displacement processes on a large model, specific features of asphaltene sedimentation and immovable residual oil formation in a porous medium were identified. The difference between the residual oil compositions was shown in the zones of dispersive and diffusive oil displacement by solvent. The impact of the solvent composition on the asphaltene concentration in the residual oil in a reservoir model and the cumulative oil recovery was assessed upon the example of the Ashalchinsk field ultra-vicious oil using n-hexane as a basic solvent with toluene and nonylphenol additives.

Solution of problems of oil reservoirs flooded with water using polymer-dispersed systems on a multiprocessor computer system

The paper provides the results of the numerical simulation of the impact of polymer-dispersed systems on oil reservoirs in order to increase the flow resistance of flooded areas and to involve nonmoving or slow-moving oil reserves in active development. The mathematical model of this process was built based on the known laws of the conservation of mass and momentum. The capillary model of the porous medium was used to construct closure relations that allowed us to describe the formation of polymer-dispersed components and their influence on a porous medium. The complexity of solving the problem of the impact of polymer-dispersed systems on the process of oil displacement by water from a porous medium is related to the three-dimensionality and nonstationarity processes of filtration, as well as the need to calculate the fields of polymer concentration, pressure and saturation fields, and the structural changes in porosity and permeability at each time step and at each point in space. All these factors require significant computer time and resources. The paper presents the algorithm of parallel calculations using a multiprocessor computer system with the MPI library. Calculations on a real field demonstrated the efficiency of the algorithm.

Nanoscience Applied to Oil Recovery and Mitigation: A Multiscale Computational Approach

ABSTRACTWith emergence of nanotechnology, it is possible to control interfaces and flow at nanoscale. This is of particular interest in the Oil and Gas industry (O&G), where nanoscience can be applied on processes such as Enhance Oil Recovery (EOR) and oil mitigation. On this direction, one of potential strategies is the so called Nano-EOR based on surface drive flow, where mobilization of hydrocarbons trapped at the pore scale can be favored by controlling by the chemical environment through “wettability modifiers”, such as functionalized nanoparticles (NP) and surfactants. The challenge consists then to search for optimal functionalized NP for oil recovery and mitigation at the harsh conditions found in oil reservoirs. Here, we introduce a hierarchical computational protocol based on the role of NP interfacial and wetting properties within oil/brine/rock interfaces to the fluid displacement in pore network models (PNMs). This integrated multiscale computational protocol ranges from first principles calculations, to determine and benchmark interatomic potentials, which are coupled with molecular dynamics (MD) to characterize the descriptors (interfacial properties and viscosity). The MD results are then mapped into Lattice Boltzmann method (LBM) simulation parameters to model the oil displacement process in PNMs at the microscale. Here, we show that this multiscale protocol coupled with Machine Learning techniques can be a resourceful tool to explore the potentialities of chemical additives, such as NP and surfactants, for the oil recovery process and investigate the effects of interfacial tension and wetting properties on the fluid behavior at both nano and microscales.

Mapping three-dimensional oil distribution with π-EPI MRI measurements at low magnetic field

Magnetic resonance imaging (MRI) is a robust tool to image oil saturation distribution in rock cores during oil displacement processes. However, a lengthy measurement time for 3D measurements at low magnetic field can hinder monitoring the displacement. 1D and 2D MRI measurements are instead often undertaken to monitor the oil displacement since they are faster. However, 1D and 2D images may not completely reflect the oil distribution in heterogeneous rock cores.In this work, a high-speed 3D MRI technique, π Echo Planar Imaging (π-EPI), was employed at 0.2T to monitor oil displacement. Centric scan interleaved sampling with view sharing in k–t space was employed to improve the temporal resolution of the π-EPI measurements. A D2O brine was employed to distinguish the hydrocarbon and water phases. A relatively homogenous glass bead pack and a heterogeneous Spynie core plug were employed to show different oil displacement behaviors. High quality 3D images were acquired with π-EPI MRI measurements.Fluid quantification with π-EPI compared favorably with FID, CPMG, 1D-DHK-SPRITE, 3D Fast Spin Echo (FSE) and 3D Conical SPRITE measurements. π-EPI greatly reduced the gradient duty cycle and improved sensitivity, compared to FSE and Conical SPRITE measurements, enabling dynamic monitoring of oil displacement processes. For core plug samples with sufficiently long lived T2, T2∗, π-EPI is an ideal method for rapid 3D saturation imaging.

Pore-scale modeling of oil mobilization trapped in a square cavity

In this work, water is injected to displace oil from a micro square cavity. Fluids are incompressible, Newtonian and immiscible. The governing equations of the two-phase, transient, laminar, isothermal flow problem are solved numerically using Ansys Fluent software coupled with volume of fluid technique and appropriated numerical parameters. The qualitative and quantitative results are obtained following the volumetric oil fraction along the spatial domain and time. The methodology proposed allows a correct description of the oil displacement process, demonstrating its complexity and dependence of physical parameters. Oil recovery factor is higher when interfacial tension is low and water is the wetting fluid.

Monitoring Oil Displacement Processes with k‐t Accelerated Spin Echo SPI

Monitoring Oil Displacement Processes with k‐t Accelerated Spin Echo SPI

Molecular Dynamics Simulation of the Oil Detachment Process within Silica Nanopores

We investigated the effect of surfactants on the oil displacement process inside a nanoscale silica pore using molecular dynamics simulations. First, an oil cylinder was built inside a silica pore to mimic residual oil in the porosity of the reservoir rock after water flooding. In the simulations, we focused on a layering organization of oil molecules adsorbed onto the pore surface, and then a series of equilibrium MD simulations were run to obtain the organization structures of the oil drop in the presence or absence of surfactant molecules. These simulated results showed that the surfactant could disturb the layering organization of the oil drop, since the hydrophobic chains of surfactant molecules could penetrate into the oil phase. And around the polar head of the surfactant, water molecules could form water channels between the oil phase and solid surface, which is vital to the displacement process. Finally, we used steered molecular dynamics (SMD) method to mimic the displacement and migration proce...

Combining molecular dynamics and lattice Boltzmann simulations: a hierarchical computational protocol for microfluidics

A hierarchical computational protocol is introduced to investigate the role of interfacial and wetting properties to the fluid displacement in hydrophilic pore network models (PNMs). Based on the combination of molecular dynamics (MD) and lattice Boltzmann method (LBM) simulations at both nano- and microscales, we study the role of dispersed functionalized \(\hbox {SiO}_{2}\) nanoparticles (NP) in brine to the oil displacement process in a clay (montmorillonite—MMT) pore structure. Our MD calculations indicate that dispersion of NP, with different hydrophilic properties, in brine solution reduces the interfacial tension between oil and brine, followed by an increase in the contact angle. The lowest interfacial tension and highest contact angle are for the hydrophilic NP functionalized with polyethylene glycol groups. By mapping the properties obtained from MD into LBM simulation parameters, we explore the oil displacement process in hydrophilic PNMs at the microscale. For all systems, the Young–Laplace filling rules are obeyed and, due to the finger formation, the displacement efficiency decreases as the capillary number increases. It was observed that, with the inclusion of NP, a reduction in interfacial tension associated with an increase in the contact angle may enhance the oil displacement process in hydrophilic pore systems at the microscale. The proposed computational protocol can be a versatile tool to explore the potentialities of chemical additives, such as NP, for the oil recovery process and investigate the effects of interfacial tension and wetting properties on the fluid behavior at both nano- and microscales.

Monitoring oil displacement processes with k-t accelerated spin echo SPI.

Magnetic resonance imaging (MRI) is a robust tool to monitor oil displacement processes in porous media. Conventional MRI measurement times can be lengthy, which hinders monitoring time-dependent displacements. Knowledge of the oil and water microscopic distribution is important because their pore scale behavior reflects the oil trapping mechanisms. The oil and water pore scale distribution is reflected in the magnetic resonance T2 signal lifetime distribution. In this work, a pure phase-encoding MRI technique, spin echo SPI (SE-SPI), was employed to monitor oil displacement during water flooding and polymer flooding. A k-t acceleration method, with low-rank matrix completion, was employed to improve the temporal resolution of the SE-SPI MRI measurements. Comparison to conventional SE-SPI T2 mapping measurements revealed that the k-t accelerated measurement was more sensitive and provided higher-quality results. It was demonstrated that the k-t acceleration decreased the average measurement time from 66.7 to 20.3 min in this work. A perfluorinated oil, containing no (1) H, and H2 O brine were employed to distinguish oil and water phases in model flooding experiments. High-quality 1D water saturation profiles were acquired from the k-t accelerated SE-SPI measurements. Spatially and temporally resolved T2 distributions were extracted from the profile data. The shift in the (1) H T2 distribution of water in the pore space to longer lifetimes during water flooding and polymer flooding is consistent with increased water content in the pore space. Copyright © 2015 John Wiley & Sons, Ltd.

Conversion of Acidic Heavy Resid to Surfactant for Separating Water-Oil Emulsions and Increasing Oil Production

Based on analysis of acidic heavy resid processing technologies with production of surfactants, we are proposing a new processing method allowing for multifunctional oilfield reagent production, which consists in removal of free sulfuric acid from the acidic heavy resid by mixing with water in a 1:6 ratio and further neutralization of the obtained solution with ammonia to pH 8–9. To determine the functional properties of the surfactant produced, we used a liquid solution and a crystalline powder obtained by evaporation. The reagent is distinguished by high detergent (up to 97%) and demulsifying (85%) capacity. The results of mathematical modeling of the oil displacement process using the Buckley-Leverett function (equation) showed that the oil extraction coefficient rises to 0.66 (oil viscosity 50 mPa·sec) when solution of the reagent is injected into the reservoir. Laboratory bench tests showed rise of oil extraction coefficient to 0.73 (oil viscosity 30 mPa·sec). Thus, the reagent can be used as demulsifier, oil displacement agent, and technical detergent.

A New Correction Method for Oil–Water Relative Permeability Curve on the Basis of Resistivity and Water Saturation Relationship

Oil–water relative permeability curve constitutes important basic data in reservoir engineering. Given the influence of dead volume on experimental apparatus, the actual oil–water relative permeability curve cannot be obtained when the unsteady-state method is adopted to measure oil–water relative permeability. In this paper, on the basis of the analysis of the influence of dead volume on oil–water relative permeability, we summarize the conventional methods used to overcome dead volume and then propose the use of relationship theory between resistivity and water saturation to calibrate the oil–water relative permeability curve. This method mainly aims at to measure the resistance values at both ends of the core by using a resistance-measuring instrument. Meantime, the Archie formula is used to calibrate the relational expression of core resistivity and water saturation based on the steady-state experimental method. Therefore, the core of the actual cumulative oil production and the average water saturation can be calculated, and then oil–water relative permeability can be accurately computed without the influence of dead volume. By comparing the oil displacement process of dead volume calculated through two different methods (probability subtraction and resistivity methods), the crude oil in dead volume is found to be displaced at the beginning of the displacement. The oil–water relative permeability curve corrected through resistivity method can eliminate the influence of dead volume and iterative error in calculation, and is consistent with the law of the actual development of oilfield, which has certain theoretical and practical application values.

The effect of saturation history on three-phase relative permeability: An experimental study

We investigate the effect of different saturation histories relevant to various oil displacement processes (including secondary and tertiary gas injections) on three-phase gas/oil/brine relative permeabilities of water-wet sandstone. It is found that three-phase water (wetting phase) relative permeability is primarily a function of water saturation and shows no dependency upon saturation history. Three-phase gas (nonwetting phase) relative permeability is also a function of gas saturation as well as the direction of gas saturation change. Three-phase relative permeability to oil (intermediate-wetting phase) appears to depend on all phase saturations, and saturation history have no significant impact on it. Three-phase oil relative permeability shows weak sensitivity to initial oil saturation prior to gas injection. The functional forms of oil relative permeability with saturation, particularly at low oil saturations, are also examined. It is observed that, at high oil saturations where networks of oil-filled elements govern oil flow, oil relative permeability exhibits a quartic form with oil saturation whereas, at low oil saturations where flow is believed to be controlled by layer drainage, it shows a quadratic form . The quadratic form of three-phase oil relative permeability is consistent with the theoretical interpretation of layer drainage at the pore scale.

Применение теплового воздействия в коллекторе двойной проницаемости, насыщенном высоковязкой нефтью. Теория

HEAT TREATMENT APPLICATION FOR DUAL PERMEABLE HEAVY OIL RESERVOIR. THEORY Background Designing the enhanced oil recovery (EOR) methods decision to use the thermal treatment method is usually based on the laboratory experiments. In the case of the development of heavy oil dual permeable reservoir the laboratory data are insufficient because they do not reflect the processes of oil displacement in the presence of high heterogeneity of reservoir permability. Aims and Objectives to establish the influence of heterogeneity of reservoir permeability for dual permeable collector on the efficiency of heat treatment. Methods There were applied the hydrodynamic model which, on the one hand, contains data from laboratory studies, and on the other hand, simulates the macroproperties of collector. Results 1. Efficiency of heat treatment, i.e. hot water injection to the dual permeable reservoir depends on the residual oil production of fractured layers. Heat treatment of heavy oil deposits in dual permeable reservoir has a significant results in the case when the fractured layer till the beginning of the technology application has not been developed, but the effect from the use of that technology is significantly delayed from the start of application of the technology, i.e., requires injection of large volumes of hot water. 2. If the fractured layer till the beginning of the technology application is partially or fully developed, then the effect of injection of hot water is intermittent and not significant in magnitude. At the same time there is a rapid growth of watering; during the heat treatment of dual permeable reservoirs watering is almost always higher than during the isothermal flooding.

Study of Gellan for Polymer Flooding

This article reports the efficiency of polymer-gellan as an oil displacement agent in comparison with water and polyacrylamide (PAM), which is traditionally used in the oil industry. The terrigenous and carbonate rocks used as core materials were characterized by scanning electron microscope. The porosity and permeability of the core materials were also determined. Sol-gel transition of polysaccharide-gellan in the presence of various salts was studied. It was found that the effectiveness of salts to enhance gelation follows this order: CaCl2 ≈ MgCl2 > KCl > NaCl. Influence of storage time and temperature on the viscosity of gellan was evaluated. Laboratory experiments on water flooding and polymer flooding methods were carried out on sand-packed model. Results of oil displacement experiments from sand-packed model and core samples were compared. It was shown that gellan and PAM show almost equal values of the oil displacement coefficient, which is 60–65%, while injection of water gives only 30–45%. Oil displacement process was visualized on cross sections of sand-packed model. Optimal concentration of gellan solution for oil displacement, which depends on absolute permeability of rock, was found.

The Description of Oil Displacement Mechanism in Steam Injection of Multi-Field Synergy with Exergy Transfer

Steam injection is a most effective way for improving heavy oil recovery efficiency, and it has academic and practical significance for the mechanism of multi-field synergy oil displacement. Mechanism of “diversified” oil displacement which is obtained by traditional study methods in the exploitation territory of oil and gas fields has both respective roles and mutual cross shortages. To describe and analyze the displacement process of multi-field coupling with exergy transfer can simplify this kind of problem by introducing a unified goal-driving exergy. It needs to use the method of theoretical modeling, numerical simulation and experimental validation to study the basic law of exergy transfer in the oil displacement process of multi-field synergy, make a thorough research for the flooding process of steam injection with exergy transfer theory and reveal the oil displacement mechanism in steam injection of multi-field synergy. Thus the theory instruction and technical support can be provided to improve reservoirs producing degree and extraction ratio.