Secondary Oil Recovery Process Research Articles

Modeling and semi-analytical solution for immiscible and miscible fingers formation during enhanced oil recovery

ABSTRACT The fingering phenomenon arises during the secondary and tertiary oil recovery processes when injected fluid (water, gases, nano/biomaterials, or polymer particles) shoots through a porous medium at a relative speed. Oil recovery is influenced by various factors including the fluid type, capillary pressure, permeability, and porous material structure. All these elements play crucial roles in determining the success and efficiency of the oil recovery process. Many scientists have debated the fingering phenomenon from different perspectives. Here, we developed mathematical models with and without considering mass flow rates of oil and water for an inclined oil layer flowing through a homogenous porous medium to generate immiscible fingers. Furthermore, a mathematical model of miscible viscous finger formation with carbonated water injection (flooding) during the enhanced oil recovery process (EOR) has been analyzed in this paper. To solve each of these mathematical models, we used the recently developed approach known as the Method of Directly Defining the inverse Mapping (MDDiM). We found approximate solutions to the nonlinear partial differential equations (PDEs), which describe each modeling of the fingering phenomenon in a homogeneous porous medium by incorporating gravitational effects for several types of flooding and discussed the effects of the saturation rate.

Study of imbibition phenomenon in homogeneous porous medium model for oil recovery with temporal-fractional approach

In this article, the phenomenon of countercurrent imbibition in a specific displacement method occurs within a dipping homogeneous porous medium. This phenomenon plays a vital role in the process of oil recovery, which motivates our analysis. To overcome the difficulties associated with the nonlinear partial differential equation governing the countercurrent imbibition phenomenon, we have been using two distinct methods: the natural transform decomposition method and the variational iteration transform method with their convergence analysis for solutions. These techniques give different perspectives and enable us to obtain approximate solutions. Notably, both the proposed methods demonstrate the potential for substantial production of oil during the secondary oil recovery process in the petroleum industry. The obtained results by the proposed methods show the efficiency in optimizing the oil recovery rate.

Predictive modeling of oil and water saturation during secondary recovery with supervised learning

In the petroleum reservoir, the secondary oil recovery (SOR) process is employed by injecting water into wells to enhance the moment of oil toward the production wells. The SOR process gives rise to the instability (fingering) phenomena due to the injecting force and the difference in the wettability and viscosity of the oil and water at the common interface. Since the late 1800s, mathematical models of petroleum reservoirs have been extensively used in the oil and gas industry. In this paper, we investigated the saturation of two immiscible fluid (oil and water) flows through homogeneous porous media during the SOR process by solving the modeled partial differential equation using the supervised machine learning algorithm based on feedforward back-propagated neural networks (FFBNNs) and Levenberg–Marquardt (LM) optimization algorithm. The designed scientific computing technique (FFBNN-LMA) is further employed to study the detailed sensitivity analysis of the approximate solutions. Performance measures like average absolute deviations, Theils' inequality measure, regression, and Nash–Sutcliffe model efficiency coefficient.

Microscopic experiment study on mechanisms of oil-gas interaction and CO2 -surfactant flooding with different temperatures and pressures

For secondary and tertiary oil recovery processes, the interfacial interactions between injected gas and crude oil contributes significantly at the pore-scale. We experimentally examine the effect of temperatures, pressures and surfactants on interfacial interaction, contact angle and oil displacement efficiency of CO2 flooding at the pore-scale using microfluidics. Two types of flow channel designs are utilized in this study, blind end of direct channels and curved channels with different diameters. The results indicate that increasing pressure and adding surfactants can promote the contact between oil and gas and reduce the interfacial tension, which has a certain impact on oil displacement efficiency. In the process of gas flooding, CO2 dissolution, expansion and miscibility are the key oil-gas interactions. The results of experiments in curved and direct channels show that the curved channels increase the resistance of fluid flow and limit the contact between CO2 and oil. And with the decrease of the porous medium radius, the capillary action in the pores increases, and the higher the viscous force needed for displacing the oil, which will affect the interaction between oil and gas and the oil recovery in micro pores. Then, two non-ionic alkoxylated surfactants (i.e. ethylene glycol butyl ether and Span 80) were selected to enhance the interaction between CO2 and crude oil. The presence of surfactants increases the solubility of CO2 in crude oil, which reduces the interfacial tension of the system and results in higher oil recovery.

Control of reservoir souring by incomplete nitrate reduction in Indian oil fields

Reservoir souring is the increased sulfide concentration in oil production fluid, and it's the major problem faced during the secondary oil recovery process. Recently, nitrate injection emerged as a souring control strategy by inhibiting sulfate-reducing bacteria that cause souring. However, this strategy showed limited success due to the complete reduction of nitrate into nitrogen. The present study revealed that souring could be controlled by incomplete reduction of nitrate to nitrite at high temperatures (>55 °C) in Indian oil fields. Present study showed that, at 55 °C incomplete nitrate reduction led to the accumulation of nitrite and control of souring. This incomplete nitrate reduction was due to under-expression of the nitrite reductase gene at 55 °C. At 37 °C, nitrate and nitrite reductase genes were expressed consecutively, but at 55 °C, nitrite reductase gene expression decreased significantly and led to nitrite accumulation.

Fingero-imbibition phenomenon with magnetic field effect in two-phase flow through porous medium

This paper discusses the problem of fingero-imbibition phenomenon with magnetic field effect. The problem arises in two-phase flow through homogeneous porous medium during secondary oil recovery process. The mathematical formulation gives us one-dimensional nonlinear partial differential equation. Homotopy analysis method is adopted to solve the governing equation. The solution is discussed numerically and graphically with the help of Mathematica BVPh package.

On the Linear Stability Problem for a Three-Layer Displacement in a Porous Media

In this paper, we study the secondary oil recovery process. The oil from a porous reservoir at low pressure is pushed by a forerunner, less viscous fluid (a polymer solute). Then the well-known Saffman-Taylor instability appears. Some authors tried to minimize this instability by using a succession of intermediate liquids with constant viscosities - the multi-layer model. The surface tensions on the interfaces between liquid layers are a stabilizing factor. In some previous papers, we proved some contradictions of this multi-layer model. However, we considered that the corresponding stability problem has a solution. This model's first step (and the mathematical basis) is the three-layer model, with a single intermediate liquid. We prove that the linear stability problem for the three-layer model has no solution (in general) - the growth rates of perturbations may not exist. On the contrary, an intermediate liquid with a suitable variable viscosity can almost suppress the Saffman-Taylor instability, even if the surface tensions are missing [17].

Influence of Injection Rate and Oil Viscosity on Viscous Fingering – Simulation Prediction

Waterflooding is a secondary oil recovery process that commonly utilized. However, there are several factors affecting the efficiency of water-flooding. Current research focused on the effects of injection rate and oil viscosity on the waterflooding efficiency. Fluid Structure Interaction (FSI) is utilized to predict the effect of the injection rate and oil viscosity towards waterflooding. Volume of fluid (VOF) and Realizable k- ɛ models are utilized in this research. Ergun’s equation also utilized in this research for estimation of permeability and inertial loss within the porous medium. The research found viscous fingering occurred when the mobility ratio is more than unity and instability number, Ni > 1000. The phenomenon of viscous fingering is directly affected by injection rate and viscosity ratio. The phenomenon directly affects directly sweep efficiency during waterflooding process thus affecting oil recovery process. The research found as injection rate and viscosity ratio increase; viscous fingering predominantly seen within the porous medium.

Efficiency of ionic liquid/polymer flooding combined with smart water injection on oil recovery through secondary and tertiary patterns using Iranian carbonate rock

The current investigation utilizes direct injection of modified smart water (SW) after oil flooding stage (secondary oil recovery process) instead of injecting the solution after water flooding (tertiary oil flooding). Before performing these types of core flooding experiments, viscosity, interfacial tension (IFT), and wettability alteration besides the effect of ionic liquids (ILs) on the IFT reduction are investigated at the presence of hydrolyzed polyacrylamide (HPAM) dissolved in SW. The results show the oil recovery of 63.5% by injecting SW/polymer while individual injection of water leading the oil recovery of 23.9% based on original oil in place (OOIP). Besides, further core-flooding experiments reveal that injecting SW/polymer solution modified by IL-based surfactants (SWPIL) enhances the recovery to 69.8 and 73.9% based on OOIP for 1-dodecyl-3-methylimidazolium chloride ([C12mim][Cl])) and 1-octadecyl-3-methylimidazolium chloride ([C18mim][Cl])) during the secondary stage. Finally, performing core-flooding experiments with a soaking time of 21 days reveal 87.0 and 89.3% of ultimate oil recovery which can be correlated to IFT reduction while the remained portions (13 and 10.7%) belong to the wettability alteration effect.

Inyección de emulsiones en núcleos empacados de arena Ottawa y arenisca Berea como método de recuperación mejorada de petróleo

Two oil-in-water emulsion systems with drop size less than 6 µm were evaluated to be used as part of an enhanced oil recovery method. Oil recovery tests were run through a forced imbibition study simulating secondary and tertiary oil recovery processes in porous media such as packed cells with Ottawa sand and Berea sandstone cores. The results show that the emulsions exhibited higher recovery percentage in Berea sandstone than the one obtained with Ottawa-sand-packed cores. Crude-oil-based emulsion showed recovery efficiency above 18.1 % in Berea sandstone at a flow rate of 0.16 mL/min at 78 ºC.

Chemical computational approaches for optimization of effective surfactants in enhanced oil recovery

Abstract The surfactant flooding becomes an attractive method among several Enhanced Oil Recovery (EOR) processes to improve the recovery of residual oil left behind in the reservoir after secondary oil recovery process. The designing of a new effective surfactant is a comparatively complex and often time consuming process as well as cost-effective due to its dependency on the crude oil and reservoir properties. An alternative chemical computational approach is focused in this article to optimize the performance of effective surfactant system for EOR. The molecular dynamics (MD), dissipative particle dynamics (DPD) and density functional theory (DFT) simulations are mostly used chemical computational approaches to study the behaviour in multiple phase systems like surfactant/oil/brine. This article highlighted a review on the impact of surfactant head group structure on oil/water interfacial property like interfacial tensions, interface formation energy, interfacial thickness by MD simulation. The effect of entropy in micelle formation has also discussed through MD simulation. The polarity, dipole moment, charge distribution and molecular structure optimization have been illustrated by DFT. A relatively new coarse-grained method, DPD is also emphasized the phase behaviour of surfactant/oil/brine as well as polymer-surfactant complex system.

Molecular Dynamics Study on the Effects of Metal Cations on Microscale Interfacial Properties of Oil–Water-Surfactant System

Water flooding is a secondary oil recovery process where oil from porous rocks is displaced by high-pressure water. Often, water with high salinity was used in this process. In this work, the effects of metal cations on interfacial properties of oil–water-surfactant flooding systems were investigated using molecular dynamics simulation. The results show that the addition of metal cations can cause a slight decrease of the interfacial thickness and the greatly enhanced interaction between the polar head group of surfactant and water molecules, which effectively restrain the water molecules nearby the polar head group. The diffusion coefficients of water molecules in oil–water-surfactant system decrease in the presence of the metal cations. The results of the interface information energy show that the addition of metal cations makes the oil–water-surfactant system more stable. The order parameter analysis showed that the surfactant molecules become more ordered in the normal direction of the interface. Our results demonstrated that the enhanced interaction between water molecules and surfactant head groups due to the existence of metal cations is the driving factor for the change of interfacial properties, especially the interfacial orientation of surfactants. In brief, the most important contribution of our work is the first demonstration of that the enhanced interaction between water molecules and surfactant head groups due to the existence of certain metal cations is the driving factor for the change of interfacial properties especially the interfacial orientation of surfactants. Our work should be valuable for the understanding of interfacial phenomenon of oil–water-surfactant systems and their industrial applications such as for oil displacement.

Analysis of Multi-Phase Flow Through Porous Media for Imbibition Phenomena by Using the LeNN-WOA-NM Algorithm

The flow of fluids in multi-phase porous media results due to many interesting natural phenomena. The counter-current water imbibition phenomena, that occur during oil extraction through a cylindrical well is an interesting problem in petroleum engineering. During the secondary oil recovery process, water is injected into a porous media having heterogenous and homogenous characteristics. Due to the difference in viscosities of fluids in oil wells, the counter-current imbibition phenomenon occurs. At that moment, the imbibition equation V <sub xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">i</sub> =-V <sub xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">n</sub> is satisfied by the viscosities of oil and water. In this article, we have analyzed the governing mathematical model of the imbibition phenomenon occurring during the secondary oil recovery process. A new soft computing algorithm is designed and adapted to analyze the mathematical model of dual-phase flow in detail. Weighted Legendre polynomials based artificial neural networks are hybridized with an efficient global optimizer the Whale Optimization Algorithm (WOA) and a local optimizer the Nelder-Mead algorithm. It is established, that our algorithm LeNN-WOA-NM is efficient and reliable in calculating high-quality solutions in less time. We have compared our experimental outcome with state-of-the-art results. The quality of our solutions is judged based on values of absolute errors, MAD, TIC, and ENSE. It is obvious that LeNN-WOA-NM algorithm can solve real application problems efficiently and accurately.

Direct numerical simulations of water flooding process through digitized porous rocks

Water flooding is a secondary oil recovery process where oil from porous rocks is displaced by high pressure water. In this paper we focus on the direct numerical simulation of multiphase flows through complex solid structures with wettability effects using a coupled immersed boundary and volume of fluid method (IBM-VOF). Our method is tested for a wide range of validation/verification cases. The water flooding process through Fontainebleau sandstone is simulated for porosities between 0.15 and 0.25, at representative pore-scale Reynolds and capillary numbers. First, we quantify the temporal change in oil saturation, phase pressure difference and oil/water interstitial velocities to study the mobility of oil through the rocks. Further, we focus on the oil-water interfacial surface area and the specific length scale to study the growth of viscous fingers inside pores. Finally, we evaluate different energies and dissipation rates to understand the energy exchange encountered in the water flooding process.

Approximate solution of imbibition phenomenon arising in heterogeneous porous media by optimal homotopy analysis method

This paper deals with approximate homotopy series solution of imbibition phenomenon occurring in multiphase flow during the secondary oil recovery process. In heterogeneous porous media, the geometry of pores is irregular while in homogeneous porous media, the geometry of pores is uniformly same. The comparative study of counter-current imbibition phenomenon in heterogeneous and homogeneous porous medium has been also discussed. The governing partial differential equation obtained by mathematical formation of imbibition phenomenon has been solved by the optimal homotopy analysis method. The numerical as well as graphical interpretation of the solution have been given.

Viability of carbonated water injection (CWI) as a means of secondary oil recovery in heavy oil systems in presence and absence of wormholes: Microfluidic experiments

In this study, the performance of carbonated water injection (CWI) as a means of secondary oil recovery process was investigated. A series of flooding experiments were carefully designed and conducted in two state-of-the-art micromodels representing single and dual permeability porous media. The dual permeability micromodel is referring to a model with 17 high permeability channels mainly to mimic wormholes generated in unconsolidated sandstone reservoirs during sand production. Prior to CWI tests, waterflooding (WF) tests were carried out in both single and dual permeability micromodels saturated with two heavy crude oils (Type-I, °API = 20.44 and Type-II, °API = 15.49) to investigate the displacement performance of conventional and well known waterflooding technique. Next, through a series of flooding experiments performed at constant injection rate of qinj = 0.05 cm3/min and temperature of Texp = 21 °C, the effect of oil °API gravity on efficiency of CWI was examined. Results obtained for Type-I crude oil from a single permeability micromodel showed that the ultimate oil recovery of CWI can be increased by about 9% as compared to that of conventional WF. Furthermore, the analysis of the images taken during the displacement process of CWI showed wider distribution of frontal advancement compared to that of conventional WF when conducted in the same heavy oil saturated micromodel. It was also observed that for Type-II crude oil (°API = 15.49), the recovery factor was improved by 2.2% under the same conditions with that of conventional WF when performed in a single permeability micromodel. Therefore, the comparative evaluation of the performance of CWI conducted in two heavy oil systems to a single permeability micromodel showed 4.8% of improvement per one degree increase in oil °API gravity under the conditions of this study. Similarly, a series of experiments were conducted with both heavy oil samples in a dual-permeability micromodel where 17 high permeability channels representing dilated regions (or wormholes) were included in the model. The carbonated water injection implemented in the dual permeability micromodel saturated with heavy oil Type-II (°API = 15.49) resulted in 23.5% improvements in the recovery factor over single permeability case at nearly 1.6 PVs of injection at aforementioned experimental conditions and operations. Results of this study showed that CWI is a viable option for enhanced oil recovery in heavy oil reservoirs. Additionally, CWI has additional benefits through CO2 storage and carbon tax credits, though less than immiscible and miscible CO2 injection processes. Therefore, it is crucial to consider this relatively easier to implement alternate option prior to other costly enhanced oil recovery (EOR) methods.

Optimization of contact angle and interfacial tension measurements for fluid/rock systems at ambient conditions

Quantification of interfacial tension (IFT) and contact angles is essential to characterize reservoir fluid-fluid and rock-fluid interactions. However, these measurements are highly dependent on chemical structure, surface residues, system conditions, flow dynamics and interface interactions. Interfacial interactions are specifically important for secondary and tertiary oil recovery processes where water or brine is injected to recover residual oil through complex multi-phase - rock/brine/oil- interactions Due to the delicate interactions across the interfaces, these systems are subjected to variations and inconsistencies that might be difficult to eliminate, thus, affecting the reliability, reproducibility, and certainty of the data. Therefore, reliable measurements need to eliminate fundamental sources of error and remove surface contaminants. To optimize these measurements, the presented methods take a holistic approach to carefully and reliably optimize the procedure for interfacial tension and contact angle measurements for fluid-fluid and rock-fluid interaction studies at ambient conditions (22.0 ± 2 °C and atmospheric pressure).•The presented method ensures minimization of impurities that alter interfacial tension measurements;•Enhanced preparation for tested surfaces for contact angle measurements, and;•Optimization of procedure at ambient conditions

The combined approach to obtain approximate analytical solution of instability phenomenon arising in secondary oil recovery process

Instability phenomenon mainly occurs in secondary oil recovery process due to viscosity difference of water and oil. Mathematical modeling of this phenomenon yields the non-linear partial differential equation. The homotopy perturbation new integral transform method has been proposed to solve this non-linear partial differential equation subject to appropriate initial and boundary conditions. It is concluded that the saturation of injected water $$S_\mathrm{w}(X, T)$$ is increasing during instability phenomenon, when length of fingers(perturbance) and time increases.

Investigating the effect of nano-silica on efficiency of the foam in enhanced oil recovery

Due to the vast production of crude oil and consequent pressure drops through the reservoirs, secondary and tertiary oil recovery processes are highly necessary to recover the trapped oil. Among the different tertiary oil recovery processes, foam injection is one of the most newly proposed methods. In this regard, in the current investigation, foam solution is prepared using formation brine, C19TAB surfactant and air concomitant with nano-silica (SiO2) as foam stabilizer and mobility controller. The measurements revealed that using the surfactant-nano SiO2 foam solution not only leads to formation of stable foam, but also can reduce the interfacial tension mostly considered as an effective parameter for higher oil recovery. Finally, the results demonstrate that there is a good chance of reducing the mobility ratio from 1.12 for formation brine and reservoir oil to 0.845 for foam solution prepared by nanoparticles.

Synthesis and characterization of eight hydrophilic imidazolium-based ionic liquids and their application on enhanced oil recovery

In order to difficulties in producing large amount of crude oil and remaining oil by primary and secondary oil recovery processes, enhanced oil recovery (EOR) techniques have been developed. Water injection is one of the EOR methods which has shown great potential in recent years. The water flooding process is more effective when the injected water is enriched by chemicals which improve the oil recovery by reducing interfacial tension (IFT) and alternating wettability. In this work eight long alkyl chain imidazolium based ionic liquids (ILs) including Octyl, Decyl, Dodecyl and Tetradecyl methylimidazolium and two different anions namely Chlorid and trihydrogen diphosphate (THDP), were synthesized and characterized by 1HNMR and elemental analysis. As a nobility it should be noted that ILs containing THDP anion have not been synthesized yet and they were used in upstream oil industry for the first time. Furthermore, some physicochemical properties were investigated for studied ILs as a function of temperature. The synthesized ILs were examined as additives in injected water to reduce the IFT in water flooding process. The critical micelle concentration (CMC) point and IFT of enriched sea water by ILs/crude oil, were measured as a function of ILs concentration. The results showed that ILs can be good candidates for EOR technology due to their significant behavior in IFT reduction and their low consumption. The consumed concentrations for ILs were observed at ppm levels, so they are favorable choices when economic concerns are considered. According to obtained results, as the alkyl chain was longer, the CMC point and IFT values were lower. Moreover the investigation of IFT values, revealed that ILs containing THDP anion were more efficient in IFT reduction compared with ILs including chloride anion. [C14mim][Cl] and [C14mim][THDP] were the most effective ILs which 50 and 25ppm of these ILs, reduced the IFT values to 0.65±0.04 and 0.5±0.02, respectively.