Improved Oil Recovery Processes Research Articles

Foam Propagation with Flow Reversal

With a view towards modelling the foam improved oil recovery process, fractional flow theory is used to study the dynamics of a foam as it propagates in a porous medium that is initially filled with liquid. In particular, a case is studied whereby, at a certain time, the net pressure driving the foam is decreased below the hydrostatic pressure at depth, leading to a local change in the flow direction. This is known as flow reversal. In both forward and reverse flow, the boundary between foamed gas and liquid is found as a discontinuous jump in liquid saturation. Over a certain thickness in the neighbourhood of this discontinuity, foam is finely textured, and the mobility of foamed gas drops by orders of magnitude relative to either pure gas or pure liquid. In reverse flow, however, the foam mobility itself and also the thickness over which low mobilities apply might differ from the forward flow case. Fractional flow theory reveals that the thickness of the low mobility region, and hence the resistance to motion that it presents, increases directly proportional to the distance travelled. Previous studies recognised this, but assumed the thickness of this region to be just a small fraction of the distance travelled by the discontinuity. Here, however, we demonstrate that the extent of the low mobility region, in both forward and reverse flow, accounts for a considerable fraction of the distance travelled by the foam, despite what was assumed in previous works.

Natural polymer non-covalently grafted graphene nanoplatelets for improved oil recovery process: A micromodel evaluation

Low stability of the colloidal suspension and the agglomeration phenomena of nanoparticles are the main challenges that restrict nanofluid applications in enhanced oil recovery at reservoir conditions. In this study, graphene nanoplatelets (GNPs) grafted with Gum Arabic (GA) were successfully prepared and evaluated as a cost-effective agent for chemically enhanced oil recovery. The physical and morphological properties of the GA-grafted GNPs (GA-GNPs) were characterized using Fourier transform-infrared spectroscopy, X-ray photoelectron spectroscopy, Raman spectroscopy, thermal gravimetric analysis, and transmission electron microscope. GA-GNP powder was prepared and dispersed in high-salinity brine of 30,000 ppm as the base fluid with concentrations of 0.01, 0.05, and 0.1 mg/ml. Investigation results showed that the developed nanofluids exhibited good stability at high salinity and temperature. A reduction in the value of oil–brine interfacial tension (IFT) by 61.0% in the presence of GA-GNPs was observed. The contact angle was remarkably changed from 108° to 20° (81.0% reduction) after dispersing 0.05 mg/mL of GA-GNPs in the brine, which indicates that the wettability of glass slices was altered from oil- to water-wet. After flooding GA-GNP-based brine in the glass micromodel, an augmentation in the oil recovery of approximately 15% and 19% was observed for 0.01 and 0.05 mg/ml of GA-GNPs, respectively. Hence, the wettability alteration plays a more important and effective role than IFT in improving oil recovery with even ultralow concentrations of GA-GNPs. The viscosity of the brine was remarkably improved by 63% after adding 0.05 mg/ml of the prepared GA-GNP powder, which in turn reduced the fingering phenomena during flooding noticeably. These findings indicate that the GA-GNP-based nanofluids can significantly improve the mobility of the residual oil from the porous media to the production well with high efficiency of oil displacement at reservoir conditions.

Assessment of flammability and explosion risks of natural gas-air mixtures at high pressure and high temperature

The flammability and explosion characteristics of natural gas (NG) and air mixtures at high pressure and high temperature are of great concerns for air injection IOR (improved oil recovery) process in oilfield and for natural gas combustion engines. In this study, an experimental setup is built up to measure the explosion limits (flammability limits) of methane and natural gas at elevated pressures and temperatures up to 20 MPa and 100 °C. The influences of pressure, temperature, and ignition energy and gas composition on the flammability limits, minimum oxygen content required for explosion (MinOC) and explosion energy have been investigated for methane and typical natural gas mixtures with air. High pressure and high temperature flammability limit models for natural gas-air mixtures have been proposed based on the experimental data. The experimental results show that the flammability limits of natural gas can be significantly extended at high temperature and high pressure, indicating a good flammability for combustion applications but high explosion risks in terms of the safety for the oilfield air injection process. At 100 °C and 20 MPa, the explosion limit range measured for methane in air is extended to 2.87%–64.40%vol, in contrast to the range of 4.95%–15.51%vol at the normal pressure and temperature (0.1 MPa and 25 °C), and the corresponding minimum oxygen content required for explosion can be reduced to as low as 5.74% from around 10% at the atmospheric conditions. The variation of the upper flammability limit (UFL) is more sensitive than that of the lower flammability limit (LFL) as pressure and temperature increase. Electrically heated tungsten wires were applied for the ignition, and it has been found that high ignition energy is required to ignite the gas mixtures at high pressure conditions. The peak explosion pressure (or explosion energy) is mainly depended on the composition of the flammable gas and oxygen, while it is slightly reduced at high temperature conditions and gradually increases with the initial pressure. Explosions with incomplete combustion reaction can occur at near UFL points with enormous amount of carbon black formed due to lack of oxygen, while the explosion energy can be significantly reduced at near LFL points because of lack of flammable gases. The increase of risk index at high pressure and high temperature indicates a larger explosion risk and safety concern.

Oxygen corrosion of N80 steel under laboratory conditions simulating high pressure air injection: Analysis of corrosion products

High pressure air injection (HPAI) is an effective and economic improved oil recovery process, however, the corrosion of tubing and casing in the injection well is one of the serious safety concerns which have limited its widely application. Until now the structure and composition of corrosion products formed in HPAI condition are still not fully clear because of the difficulty in simulating such a harsh environment in laboratory. In this work, the corrosion rates of N80 steel under laboratory conditions with different oxygen content (21–5% vol%), total pressure (50–20 MPa) and temperature (120–70 °C) simulating HPAI in Dagang oil field in China were investigated using weight loss measurement. The corrosion products on N80 steel surface were analyzed using scanning electron microscopy coupled with energy dispersive spectroscopy (SEM + EDS), X-ray diffraction (XRD) and transmission electron microscopy (TEM). The results show that the corrosion rate decreased with the decreasing oxygen partial pressure and temperature. Furthermore, for all the conditions, the corrosion rate was incredibly high in the simulating HPAI environment, consequently, large amount of corrosion products were formed. The corrosion products showed a two-layer structure: outer layer and inner layer. The outer layer was porous, brittle and easily flaked off, while the inner layer was more compact than outer layer. However, both layers could not effectively lower the corrosion rate of N80 steel in HPAI environment. The corrosion products were composed of hematite (α-Fe2O3), goethite (α-FeOOH), magnetite (Fe3O4) and trace amounts of Ca(OH)2 and CaO. In addition, the structure and composition of corrosion products did not change with the temperature and oxygen partial pressure in the simulating HPAI conditions.

Dynamic surfactant-aided imbibition in fractured oil-wet carbonates

Numerous studies based on static imbibition experiments at lab scale have established surfactant-aided imbibition as an improved oil recovery process for fractured oil-wet carbonate reservoirs. However, predicting performance at larger scales and at dynamic conditions (fluid flow through fracture) remains a challenge. In this study, experiments are performed on Estaillades Limestone and Texas Cream Limestone outcrop cores with varying height and diameter with permeability in the range of 8 mD to 150 mD to address this challenge. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. A 3D fine grid mechanistic simulator was used to perform lab scale validation and analyze recovery mechanism. Numerically simulated velocity and saturation profiles demonstrated the recovery mechanism to be gravity dominated flow. A new scaling function is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition.

Displacement mechanisms of air injection for IOR in low permeability light oil reservoirs

Air injection into light oil reservoirs has been proven to be a valuable improved oil recovery (IOR) process and is being successfully implemented worldwide in many oilfields. It specially offers unique technical and economic opportunities for tertiary or secondary oil recovery in light oil reservoirs with low permeability in which conventional water injection techniques have been unsuccessful and/or uneconomical. This paper provides a comprehensive overview on the oxidation and IOR process of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and the results of laboratory testing and reservoir simulation of a typical light oil reservoir, the Q131 Block. The reaction mechanisms of low temperature oxidation (LTO) and high temperature oxidation (HTO or in-situ combustion) are particularly addressed in this study. Air flooding displacement efficiency experiment was carried out without water injection, and an oil recovery of more than 40% of hydrocarbon pore volume (HCPV) was observed. A series of high-pressure oxidation experiments using the typical light oil were conducted in the temperature range of 98°C to 180°C. The results showed high oxidation and carbon dioxide (CO2) conversion rates, which are both favourable in terms of oxygen consumption. A conceptual full field compositional reservoir simulation model of the targeted low permeability block was also used to examine the reaction schemes, thermal effect of LTO reactions and IOR mechanisms. [Received: March 22, 2014; Accepted: February 7, 2016]

Displacement mechanisms of air injection for IOR in low permeability light oil reservoirs

Air injection into light oil reservoirs has been proven to be a valuable improved oil recovery (IOR) process and is being successfully implemented worldwide in many oilfields. It specially offers unique technical and economic opportunities for tertiary or secondary oil recovery in light oil reservoirs with low permeability in which conventional water injection techniques have been unsuccessful and/or uneconomical. This paper provides a comprehensive overview on the oxidation and IOR process of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and the results of laboratory testing and reservoir simulation of a typical light oil reservoir, the Q131 Block. The reaction mechanisms of low temperature oxidation (LTO) and high temperature oxidation (HTO or in-situ combustion) are particularly addressed in this study. Air flooding displacement efficiency experiment was carried out without water injection, and an oil recovery of more than 40% of hydrocarbon pore volume (HCPV) was observed. A series of high-pressure oxidation experiments using the typical light oil were conducted in the temperature range of 98°C to 180°C. The results showed high oxidation and carbon dioxide (CO2) conversion rates, which are both favourable in terms of oxygen consumption. A conceptual full field compositional reservoir simulation model of the targeted low permeability block was also used to examine the reaction schemes, thermal effect of LTO reactions and IOR mechanisms. [Received: March 22, 2014; Accepted: February 7, 2016]

Discussion of the feasibility of air injection for enhanced oil recovery in shale oil reservoirs

Abstract Air injection in light oil reservoirs has received considerable attention as an effective, improved oil recovery process, based primarily on the success of several projects within the Williston Basin in the United States. The main mechanism of air injection is the oxidation behavior between oxygen and crude oil in the reservoir. Air injection is a good option because of its wide availability and low cost. Whether air injection can be applied to shale is an interesting topic from both economic and technical perspectives. This paper initiates a comprehensive discussion on the feasibility and potential of air injection in shale oil reservoirs based on state-of-the-art literature review. Favorable and unfavorable effects of using air injection are discussed in an analogy analysis on geology, reservoir features, temperature, pressure, and petrophysical, mineral and crude oil properties of shale oil reservoirs. The available data comparison of the historically successful air injection projects with typical shale oil reservoirs in the U.S. is summarized in this paper. Some operation methods to improve air injection performance are recommended. This paper provides an avenue for us to make use of many of the favorable conditions of shale oil reservoirs for implementing air injection, or air huff ‘n’ puff injection, and the low cost of air has the potential to improve oil recovery in shale oil reservoirs. This analysis may stimulate further investigation.

Improved oil recovery in nanopores: NanoIOR.

Fluid flow through minerals pores occurs in underground aquifers, oil and shale gas reservoirs. In this work, we explore water and oil flow through silica nanopores. Our objective is to model the displacement of water and oil through a nanopore to mimic the fluid infiltration on geological nanoporous media and the displacement of oil with and without previous contact with water by water flooding to emulate an improved oil recovery process at nanoscale (NanoIOR). We have observed a barrier-less infiltration of water and oil on the empty (vacuum) simulated 4 nm diameter nanopores. For the water displacement with oil, we have obtained a critical pressure of 600 atm for the oil infiltration, and after the flow was steady, a water layer was still adsorbed to the surface, thus, hindering the direct contact of the oil with the surface. In addition, oil displacement with water was assessed, with and without an adsorbed water layer (AWL). Without the AWL, the pressure needed for oil infiltration was 5000 atm, whereas, with the AWL the infiltration was observed for pressures as low as 10 atm. Hence, the infiltration is greatly affected by the AWL, significantly lowering the critical pressure for oil displacement.

Geological uncertainty and effects of depositional sequence on improved oil recovery processes

Several emerging improved oil recovery (IOR) techniques have been proposed in the past decades with promising results. However, a systematic study of reservoir heterogeneity on these advanced processes has not yet been presented. This paper provides one of the first comparative evaluations of the effects of reservoir heterogeneity on various IOR processes from the conventional methods (waterflooding, CO2 flooding) to the emerging recovery technologies (Low-Salinity Waterflooding and CO2 Low-Salinity WAG) for wider and more successful implementation of these projects. Since weakness exists in the current simple and unrealistic models, detailed geostatistic models are employed to provide a more realistic and unbiased evaluation of reservoir heterogeneity. A new modeling approach that involves the integration of geological software, a reservoir simulator and a robust optimizer in a closed loop for generating multiple geologically driven realizations and uncertainty assessment of different recovery processes is introduced. Then a series of numerical simulations is conducted to investigate the influences of FU and CU sequences on oil recovery. Finally, the uncertainty range of reservoir heterogeneity is thoroughly evaluated using a large number of geological realizations with significant differences on porosity and permeability distributions. The effect of the K v /K h (aspect) ratio is also addressed in this study. The simulation results indicate that the depositional sequence has a dominant effect on oil recovery in all recovery processes. The CU distribution demonstrates superior performance over the FU distribution.

A study on the effects of surrounding faults on optimisation of improve oil recovery process by using a genetic algorithm self-code

There are many parameters affecting an improved oil recovery (IOR) process like production and injection rates, fault orientation, injection well placement and perforation locations. It is plausible to optimise an IOR process from the beginning of reservoir production to prevent from high changes and further cost during field development. Here a self-code genetic algorithm was coupled with MATLAB and a simulator to optimise IOR process in an oil reservoir model. Thus, 28 parameters have been optimised simultaneously and net present value (NPV) was taken as an objective function. To speed up the optimisation, it has been considered in the GA self-code to avoid simulating reservoir with previously calculated data. Moreover, the effect of the surrounding faults in the reservoir on the applied IOR process has been studied. Based on achieved results, it could be concluded that the presence of the faults in a reservoir may increase the overall displacement efficiency due to prolonging the contact time and the surface area between the flooding front and the target oil.

Foam-improved oil recovery: Modelling the effect of an increase in injection pressure.

A model, called pressure-driven growth, is analysed for propagation of a foam front through an oil reservoir during improved oil recovery using foam. Numerical simulations of the model predict, not only the distance over which the foam front propagates, but also the instantaneous front shape. A particular case is studied here in which the pressure used to drive the foam along is suddenly increased at a certain point in time. This transiently produces a concave front shape (seen from the domain ahead of the front): such concavities are known to be delicate to handle numerically. As time proceeds however, the front evolves back towards a convex shape, and this can be predicted by a long-time asymptotic analysis of the model. The increase in driving pressure is shown to be beneficial to the improved oil recovery process, because it gives a more uniform sweep of the oil reservoir by the foam.

Low-Temperature Oxidation and Characterization of Heavy Oil via Thermal Analysis

High pressure air injection (HPAI) without ignition has attracted extensive attention in the air injection based improved oil recovery (IOR) process for light oil reservoirs but was rarely proposed as an IOR process for heavy oil reservoirs. This study aims at evaluating the potential of HPAI without ignition for deep, high pressure, heavy oil reservoirs (Tahe oilfield, Tarim Basin, China). Many low-temperature oxidation (LTO) experiments were carried out to study the oxidation behavior of heavy oil under the reservoir conditions (120 °C, about 30–40 MPa) using an isothermal oxidation reactor. The produced gases were analyzed using gas chromatography for their content of O2, CO2, CO, and hydrocarbon gas (C1–C6) content. The apparent hydrogen/carbon (H/C) and molar ratio of the carbon oxides (m-ratio) were also calculated from effluent gases to analyze oxidation behavior. The effects of quartz, reservoir core (characterized by X-ray diffraction), formation water, and catalyst on LTO were analyzed. Thermogravimetry (TG-DTG) experiments were conducted to characterize the oxidation behavior and kinetics of heavy oil. The Arrhenius method was employed to calculate reaction activation energy. The isothermal oxidation experimental results show that reservoir core, formation water, and catalyst have important influences on LTO. The upgrading of heavy oil occurred in the presence of catalyst. The inflammable coke was formed, and combustion reaction happened at 40 MPa and 120 °C after oxidation for 7 days, which implies heavy oils have a spontaneous combustion potential for HPAI without ignition process in Tahe heavy oil reservoir. Simultaneously, the heavy oil upgrading indicates that HPAI without ignition process in the presence of catalyst is a promising and potential air injection based IOR technique for deep, high pressure, heavy oil reservoirs such as the Tahe oilfield.

Foam improved oil recovery: Foam front displacement in the presence of slumping

Foam is often used in improved oil recovery processes to displace oil from an underground reservoir. During the process, the reservoir is flooded with surfactant, and then gas is injected to produce foam in situ, with the foam front advancing through the reservoir. Here the effect of surfactant slumping (downward movement of surfactant in relation to a lighter phase) upon the advance of a foam front is presented. Slumping which can be associated with foam drainage, coarsening and collapse, causes a rise in mobility of the foam front specifically near the top of the front. The description of a foam front displacement for an initially homogeneous foam mobility is therefore modified to account for slumping-induced inhomogeneities. Numerical solution for the front shape shows that, although slumping transiently produces a localised concave region on the otherwise convex front, this concavity has little effect on the long term front evolution. In fact in the long-time limit, a convex kink develops on the front: an analytical solution describing the convex kink agrees very well with the numerics.

Experimental Study on Nonionic Surfactants for Minimizing Surface Adsorption as an Improved Oil Recovery (IOR) Process

Adsorption of surfactants onto the surfaces during chemical flooding is a major problem in EOR and IOR process. This happens due to blockage of capillary pores and opposite charge on the surface. The objective of this paper is to reduce adsorption of anionic surfactants by application of no nonionic surfactants as an IOR process. The methodology for Selection of surfactants for core flooding has been done based on conductivity and emulsion tests. Nonionic surfactants Ethoxylated Alcohol (EO) of 1000ppm from emulsion test has been chosen to reduce adsorption of anionic surfactants Sodium Dodecyle Sulphate (SDS) of 750ppm determined from conductivity test. Core flooding experiment with anionic surfactants has been conducted with nonionic surfactants and without the influence of nonionic surfactants. Reduction in adsorption of anionic surfactants SDS up to 1.2 pore volume has been observed in the on core flooding experiment. Keywords: Adsorption, EOR, IOR, Nonionic Surfactants

Experimental Study on Nonionic Surfactants for Minimizing Surface Adsorption as an Improved Oil Recovery (IOR) Process

Adsorption of surfactants onto the surfaces during chemical flooding is a major problem in EOR and IOR process. This happens due to blockage of capillary pores and opposite charge on the surface. The objective of this paper is to reduce adsorption of anionic surfactants by application of no nonionic surfactants as an IOR process. The methodology for Selection of surfactants for core flooding has been done based on conductivity and emulsion tests. Nonionic surfactants Ethoxylated Alcohol (EO) of 1000ppm from emulsion test has been chosen to reduce adsorption of anionic surfactants Sodium Dodecyle Sulphate (SDS) of 750ppm determined from conductivity test. Core flooding experiment with anionic surfactants has been conducted with nonionic surfactants and without the influence of nonionic surfactants. Reduction in adsorption of anionic surfactants SDS up to 1.2 pore volume has been observed in the on core flooding experiment.

Dynamic flow response of crude oil-in-water emulsion during flow through porous media

Injection of crude oil-in-water emulsion in tertiary mode has been recognized as a potential method to increase oil recovery. Better understanding of emulsion flow through porous media is needed to develop practical improved oil recovery processes based on emulsion flooding mechanisms. In this study, two sets of experiments were carried out to further investigate the flow of emulsion in consolidated sandstone core plugs. First, the efficiency of emulsion injection to improve oil recovery was evaluated in two-phase flow experiments. Second, single-phase flow experiments were designed to understand the flow of emulsion at pore scale. In these experiments, a crude oil-in-water emulsion with known drop-size distribution was injected in water-saturated Berea sandstone cores followed by water injection at increasing flow rate. The overall pressure drop and its Fast Fourier Transform were analyzed to unveil potential connections to pore level flow. The pore throat blockage-release mechanism was inferred to be linked to the acquired pressure drop oscillation. The pore-scale dynamics has been shown to depend on local capillary number and emulsion drop size. The blockage-release mechanism of the trapped drops becomes less effective as the water flow rate or equivalently, the capillary number, increases above a critical value. Also, a larger drop-to-pore size ratio results in higher required capillary number, i.e. larger viscous force to mobilize the drops in the porous media.

Double-Layer Expansion: Is It a Primary Mechanism of Improved Oil Recovery by Low-Salinity Waterflooding?

Summary Literature review shows that improved oil recovery (IOR) by low-salinity waterflooding could be attributed to several mechanisms, such as sweep-efficiency improvement, interfacial-tension (IFT) reduction, multicomponent ionic exchange, and electrical-double-layer (EDL) expansion. Although these mechanisms might contribute to IOR by low-salinity water, they may not be the primary mechanism. Therefore, the main objective of this study is to investigate if the mechanism of EDL expansion could be the principal reason for IOR during low-salinity waterflooding. Low-salinity water results in a thicker EDL when compared to high-salinity water, so we tried to eliminate the effect of low-salinity brines on double-layer expansion to show to what extent IOR is related to EDL expansion caused by low-salinity water. The double-layer expansion is dependent on the electric surface charge, which is a function of the pH of brine; therefore, the pH levels of low-salinity brines were decreased in this study to provide low-salinity brines that can produce a thinner EDL, similar to high-salinity brines. ζ-potential measurements were performed on both rock/brine and oil/brine interfaces to demonstrate the effect of brine pH and salinity on EDL. Contact angle and coreflood experiments were conducted to test different brine salinities at different pH values, which could assess the effect of water salinity and pH on rock wettability and oil recovery, and hence involvement of EDL expansion in the IOR process. ζ-potential results in this study showed that decreasing the pH of low-salinity brines makes the electrical charges at both oil/brine and brine/rock interfaces slightly negative, which reduces the double-layer expansion caused by low-salinity brine. As a result, the rock becomes more oil-wet, which was confirmed by contact-angle measurements. Moreover, coreflood experiments indicated that injecting low-salinity brine at lower pH values recovered smaller amounts of oil when compared to the original pH because of the elimination of the low-salinity-water effect on the thickness of the double layer. In conclusion, this study demonstrates that expansion of the double layer is a dominant mechanism of oil-recovery improvement by low-salinity waterflooding.

Technology Focus: EOR Performance and Modeling (January 2014)

Technology Focus This is the most exciting time for enhanced oil recovery (EOR) in recent memory. At last, almost everyone is talking about increasing recovery factors, and improved oil recovery (IOR) and EOR are being considered natural components of reservoir management. Furthermore, many traditional philosophies are being openly challenged. EOR planning is happening as part of field-development plans. Proven technologies are being adapted in new, smart ways, and new technologies are constantly evolving from research to commercial applications, making EOR projects more economical. These new directions are the result of the following factors: Most fields, including the giant ones, are maturing, and producing liquid hydrocarbons is becoming more difficult in all types of reservoirs (conventional and unconventional). Leaving approximately 70% of the in-place reserves unrecovered has been challenged. There have been developments on many fronts (e.g., advanced reservoir characterization, multiphase-flow physics, smart-well and intelligent completions, recovery research, monitoring and control technologies, EOR chemicals, EOR pilot concepts, and observation-well concepts); the collective effect of all of those is going to make new EOR projects more successful. Increasing recovery factors has been considered a fully integrated multidomain activity (from pore space to separator and everything in between). Severe production decline in tight/light (unconventional) reservoirs is making the industry think about recovery challenges. EOR has been considered during field-development planning in most recent offshore oil developments. We lived through the most active period of EOR—between the mid-1970s and the mid-1980s—and learned about recovery fundamentals then. However, if we look back at that era carefully, most of the wells were single and vertical; reservoir characterization was very elementary, with no digital geological modeling capabilities; and there were no concepts such as monitoring systems or intelligent completions. All of those factors created a significant gap between what was planned in the EOR laboratory and what was achieved in field application. Other than those implemented in extremely viscous oils (heavy-oil EOR operations), projects recovered far less than planned. Overall, such recovery gave a stigma to EOR as inherently difficult and expensive. Most of the factors that made EOR difficult and expensive are gone today. That is why we will see more fields using EOR operations in upcoming years. Broadening the scope of recovery challenge to all domains will make realizations of new reserves more likely, but this change will bring additional challenges. Recommended additional reading at OnePetro: www.onepetro.org. SPE 162701 Geomechanics Considerations in Enhanced Oil Recovery by Tadesse Weldu Teklu, Colorado School of Mines, et al. SPE 166597 BP North Sea Miscible Gas Injection Projects Review by Pinggang Zhang, BP, et al. IPTC 17157 The Development of a Workflow To Improve Predictive Capability of Low-Salinity Response by B.M.J.M. Suijkerbuijk, Shell, et al. SPE 166075 The Upscaling of Discrete Fracture Models for Faster, Coarse-Scale Simulations of IOR and EOR Processes for Fractured Reservoirs by Mun-Hong Hui, Chevron, et al.

Molecular Dynamics Studies of Fluid/Oil Interfaces for Improved Oil Recovery Processes

In our paper, we study the interface wettability, diffusivity, and molecular orientation between crude oil and different fluids for applications in improved oil recovery (IOR) processes through atomistic molecular dynamics (MD). The salt concentration, temperature, and pressure effects on the physical chemistry properties of different interfaces between IOR agents [brine (H(2)O + % NaCl), CO(2), N(2), and CH(4)] and crude oil have been determined. From the interfacial density profiles, an accumulation of aromatic molecules near the interface has been observed. In the case of brine interfaced with crude oil, our calculations indicate an increase in the interfacial tension with increasing pressure and salt concentration, which favors oil displacement. On the other hand, with the other fluids studied (CO(2), N(2), and CH(4)), the interfacial tension decreases with increasing pressure and temperature. With interfacial tension reduction, an increase in fluid diffusivity in the oil phase is observed. We also studied the molecular orientation properties of the hydrocarbon and fluids molecules in the interface region. We perceived that the molecular orientation could be affected by changes in the interfacial tension and diffusivity of the molecules in the interface region with the increased pressure and temperature: pressure (increasing) → interfacial tension (decreasing) → diffusion (increasing) → molecular ordering. From a molecular point of view, the combination of low interfacial tension and high diffusion of molecules in the oil phase gives the CO(2) molecules unique properties as an IOR fluid compared with other fluids studied here.