Engineering › Ocean Engineering

Enhanced Oil Recovery Techniques

Works Count: 50459

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Description

This cluster of papers focuses on the use of advanced imaging techniques such as X-ray computed tomography for pore-scale modeling and analysis in the context of enhanced oil recovery. It explores methods for wettability alteration, the use of nanofluids and surfactants, and the application of foam for improved recovery in porous media and reservoir rocks.

Keywords

X-ray Computed Tomography; Pore-scale Modeling; Enhanced Oil Recovery; Wettability Alteration; Nanofluids; Surfactants; Porous Media; Reservoir Rock; Microstructure Reconstruction; Foam Assisted Recovery

Physicochemical hydrodynamics: an introduction

1995-02-01

Ronald F. Probstein

Preface to the Paperback Edition. Preface to the Second Edition. Preface to the First Edition. Acknowledgments for the First Edition. Introduction. Transport in Fluids. Equations of Change. Solutions of Uncharged … Preface to the Paperback Edition. Preface to the Second Edition. Preface to the First Edition. Acknowledgments for the First Edition. Introduction. Transport in Fluids. Equations of Change. Solutions of Uncharged Molecules. Solutions of Uncharged Macromolecules and Particles. Solutions of Electrolytes. Solutions of Charged Macromolecules and Particles. Suspension Stability and Particle Capture. Rheology and Concentrated Suspensions. Surface Tension. Appendix A. SI Units and Physical Constants. Appendix B. Symbols. Author Index. Subject Index.

Microfacies Analysis of Limestones

1982-01-01

Erik Flügel

Compressible Fluid Flow and Systems of Conservation Laws in Several Space Variables

1984-01-01

Andrew J. Majda

Predictive pore‐scale modeling of two‐phase flow in mixed wet media

2004-07-01

Per H. Valvatne , Martin J. Blunt

We show how to predict flow properties for a variety of porous media using pore‐scale modeling with geologically realistic networks. Starting with a network representation of Berea sandstone, the pore … We show how to predict flow properties for a variety of porous media using pore‐scale modeling with geologically realistic networks. Starting with a network representation of Berea sandstone, the pore size distribution is adjusted to match capillary pressure for different media, keeping the rank order of pore sizes and the network topology fixed. Then predictions of single and multiphase properties are made with no further adjustment of the model. We successfully predict relative permeability and oil recovery for water wet, oil wet, and mixed wet data sets. For water flooding we introduce a method for assigning contact angles to match measured wettability indices. The aim of this work is not simply to match experiments but to use easily acquired data to predict difficult to measure properties. Furthermore, the variation of these properties in the field, due to wettability trends and different pore structures, can now be predicted reliably.

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Pore-network extraction from micro-computerized-tomography images

2009-09-14

Dong Hu , Martin J. Blunt

Network models that represent the void space of a rock by a lattice of pores connected by throats can predict relative permeability once the pore geometry and wettability are known. … Network models that represent the void space of a rock by a lattice of pores connected by throats can predict relative permeability once the pore geometry and wettability are known. Micro-computerized-tomography scanning provides a three-dimensional image of the pore space. However, these images cannot be directly input into network models. In this paper a modified maximal ball algorithm, extending the work of Silin and Patzek [D. Silin and T. Patzek, Physica A 371, 336 (2006)], is developed to extract simplified networks of pores and throats with parametrized geometry and interconnectivity from images of the pore space. The parameters of the pore networks, such as coordination number, and pore and throat size distributions are computed and compared to benchmark data from networks extracted by other methods, experimental data, and direct computation of permeability and formation factor on the underlying images. Good agreement is reached in most cases allowing networks derived from a wide variety of rock types to be used for predictive modeling.

Fluid Interfacial Phenomena

1987-09-01

J. S. Rowlinson

Polymers for enhanced oil recovery: A paradigm for structure–property relationship in aqueous solution

2011-06-03

D.A.Z. Wever , Francesco Picchioni , A.A. Broekhuis

Mechanisms of the displacement of one fluid by another in a network of capillary ducts

1983-10-01

R. Lenormand , C. Zarcone , A. Sarr

The mechanisms of displacement of one fluid by another are investigated in an etched network.Experiments show that both fluids are simultaneously present in a duct, the wetting fluid remaining in … The mechanisms of displacement of one fluid by another are investigated in an etched network.Experiments show that both fluids are simultaneously present in a duct, the wetting fluid remaining in the extreme corners of the cross-section. Calculation of displacement pressures are in good agreement with experiments for drainage, imbibition and removal of blobs. The results may be related to some flow behaviour exhibited in porous media.

Recovery of oil by spontaneous imbibition

2001-08-01

Norman R. Morrow , Geoffrey Mason

X-ray imaging and analysis techniques for quantifying pore-scale structure and processes in subsurface porous medium systems

2012-07-25

D. Wildenschild , Adrian Sheppard

Thermodynamic basis of capillary pressure in porous media

1993-10-01

S. Majid Hassanizadeh , William G. Gray

Important features of multiphase flow in porous media that distinguish it from single‐phase flow are the presence of interfaces between the fluid phases and of common lines where three phases … Important features of multiphase flow in porous media that distinguish it from single‐phase flow are the presence of interfaces between the fluid phases and of common lines where three phases come in contact. Despite this fact, mathematical descriptions of these flows have been lacking in rigor, consisting primarily of heuristic extensions of Darcy's law that include a hysteretic relation between capillary pressure and saturation and a relative permeability coefficient. As a result, the standard capillary pressure concept appears to have physically unrealistic properties. The present paper employs microscopic mass and momentum balance equations for phases and interfaces to develop an understanding of capillary pressure at the microscale. Next, the standard theories and approaches that define capillary pressure at the macroscale are described and their shortcomings are discussed. Finally, an approach is presented whereby capillary pressure is shown to be an intrinsic property of the system under study. In particular, the presence of interfaces and their distribution within a multiphase system are shown to be essential to describing the state of the system. A thermodynamic approach to the definition of capillary pressure provides a theoretically sound alternative to the definition of capillary pressure as a simple hysteretic function of saturation.

EOR Screening Criteria Revisited— Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects

1997-08-01

J.J. Taber , F.D. Martin , R. S. Seright

Summary Screening criteria have been proposed for all enhanced oil recovery (EOR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful … Summary Screening criteria have been proposed for all enhanced oil recovery (EOR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful projects have been noted. The oil gravity ranges of the oils of current EOR methods have been compiled and the results are presented graphically. The proposed screening criteria are based on both field results and oil recovery mechanisms. The current state of the art for all methods is presented briefly, and relationships between them are described. Steamflooding is still the dominant EOR method. All chemical flooding has been declining, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only CO2 flooding activity has increased continuously.

Effect of Wettability on Waterflood Recovery for Crude-Oil/Brine/Rock Systems

1995-02-01

P. P. Jadhunandan , Norman R. Morrow

Summary This paper presents a definitive account of the effect of wettability on oil recovery from Berea sandstone based on the results of more than 50 slow-rate laboratory waterfloods. Closely … Summary This paper presents a definitive account of the effect of wettability on oil recovery from Berea sandstone based on the results of more than 50 slow-rate laboratory waterfloods. Closely reproducible wettability conditions and waterflood recoveries were obtained with wettability, depending on the crude oil, brine composition, aging temperature, and initial water saturation. Maximum oil recovery by waterflooding was obtained at very weakly water-wet conditions from shortly after breakthrough up to discontinuation of the test at 20 PV of water injected. In most of the tests, coproduction of oil and water continued long after breakthrough.

Influence of brine composition and fines migration on crude oil/brine/rock interactions and oil recovery

1999-12-01

Guoqing Tang , Norman R. Morrow

Effective Correlation of Apparent Gas Permeability in Tight Porous Media

2009-07-02

Faruk Civan

Wettability Literature Survey- Part 1: Rock/Oil/Brine Interactions and the Effects of Core Handling on Wettability

1986-10-01

William G. Anderson

Wettability Literature Survey- Part 1: Rock/Oil/Brine Interactions Part 1: Rock/Oil/Brine Interactions and the Effects of Core Handling on Wettability Summary Wettability is a major factor controlling the location, flow, and … Wettability Literature Survey- Part 1: Rock/Oil/Brine Interactions Part 1: Rock/Oil/Brine Interactions and the Effects of Core Handling on Wettability Summary Wettability is a major factor controlling the location, flow, and distribution of fluids in a reservoir. The wettability of a core will affect almost all types of core analyses, including capillary pressure, relative permeability, waterflood behavior, electrical properties, and simulated tertiary recovery. The most accurate results are obtained when native- or restored-state cores are run with native crude oil and brine at reservoir temperature and pressure. Such conditions provide cores that have the same wettability as the reservoir. The wettability of originally water-wet reservoir rock can be altered by the adsorption of polar compounds and/or the deposition of organic material that was originally in the crude oil. The degree of alteration is determined by the interaction of the oil constituents, the mineral surface, and the brine chemistry. The procedures for obtaining native-state, cleaned, and restored-state cores are discussed, as well as the effects of coring, preservation, and experimental conditions on wettability. Also reviewed are methods for artificially controlling the wettability during laboratory experiments. Introduction This paper is the first of a series of literature surveys covering the effects of wettability on core analysis. Changes in wettability have been shown to affect capillary pressure, relative permeability, waterflood behavior, dispersion of tracers, simulated tertiary recovery, irreducible water saturation (IWS), residual oil saturation (ROS), and electrical properties. For core analysis to predict the behavior of a reservoir accurately, the wettability of a core must be the same as the wettability of the undisturbed reservoir rock. A serious problem occurs because many aspects of core handling can drastically affect wettability. Water-Wet, Oil-Wet, and Neutrally Wet. Wettability is defined as "the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids. "In a rock/oil/brine system, it is a measure of the preference that the rock has for either the oil or water. When the rock is water-wet, there is a tendency for water to occupy the small pores and to contact the majority of the rock surface. Similarly, in an oil-wet system, the rock is preferentially in contact with the oil; the location of the two fluids is reversed from the water-wet case, and oil will occupy the small pores and contact the majority of the rock surface. It is important to note, however, that the term wettability is used for the wetting preference of the rock and does not necessarily refer to preference of the rock and does not necessarily refer to the fluid that is in contact with the rock at any given time. For example, consider a clean sandstone core that is saturated with a refined oil. Even though the rock surface is coated with oil, the sandstone core is still preferentially water-wet. This wetting preference can be preferentially water-wet. This wetting preference can be demonstrated by allowing water to imbibe into the core. The water will displace the oil from the rock surface, indicating that the rock surface "prefers" to be in contact with water rather than oil. Similarly, a core saturated with water is oil-wet if oil will imbibe into the core and displace water from the rock surface. Depending on the specific interactions of rock, oil, and brine, the wettability of a system can range from strongly water-wet to strongly oil-wet. When the rock has no strong preference for either oil or water, the system is said to be of neutral (or intermediate) wettability. Besides strong and neutral wettability, a third type is fractional wettability, where different areas of the core have different wetting preferences. The wettability of the rock/fluid system is important because it is a major factor controlling the location, flow, and distribution of fluids in a reservoir. In general, one of the fluids in a porous medium of uniform wettability that contains at least two immiscible fluids will be the wetting fluid. When the system is in equilibrium, the wetting fluid will completely occupy the smallest pores and be in contact with a majority of the rock surface (assuming, of course, that the saturation of the wetting fluid is sufficiently high). The nonwetting fluid will occupy the centers of the larger pores and form globules that extend over several pores. In the remainder of this survey, the terms wetting and nonwetting fluid will be used in addition to water-wet and oil-wet. This will help us to draw conclusions about a system with the opposite wettability. The behavior of oil in a water-wet system is very similar to the behavior of water in an oil-wet one. JPT P. 1125

Detailed physics, predictive capabilities and macroscopic consequences for pore-network models of multiphase flow

2002-08-01

Martin J. Blunt , Matthew D. Jackson , Mohammad Piri +1 more

Flow in porous media — pore-network models and multiphase flow

2001-06-01

Martin J. Blunt

A Review of Diffusion and Dispersion in Porous Media

1963-03-01

T.K. Perkins , O.C. Johnston

Abstract Because of the influence of dispersion on miscible-displacement processes, diffusion and dispersion phenomena in porous rocks are of current interest in the oil industry. This paper reviews and summarizes … Abstract Because of the influence of dispersion on miscible-displacement processes, diffusion and dispersion phenomena in porous rocks are of current interest in the oil industry. This paper reviews and summarizes a great deal of pertinent information from the literature.Porous media (both unconsolidated packs and consolidated rocks) can be visualized as a network of flow chambers, having random size and flow conductivity, connected together by openings of smaller size. In such a porous medium, the apparent diffusion coefficient D is less than the molecular diffusion coefficient Do, as measured in the absence of a porous medium. For packs of unconsolidated granular material the ratio D/Do is about 0.6 to 0..7. For all porous rocks, both cemented and unconsolidated, the ratio of diffusion coefficients can also be represented as where F is the formation electrical resistivity factor and is the porosity.If fluids are flowing through the porous medium, dispersion may be greater than that due to diffusion alone. At moderate flow rates the porous medium will create a slightly asymmetrical mix zone (trailing edge stretched out), with the longitudinal dispersion coefficient approximately proportional to the first power of average fluid velocity (if composition is nearly equalized in pore spaces by diffusion). If the velocity in interstices is large enough, there will be insufficient time for diffusion to equalize concentration within pore spaces. In this region, longitudinal dispersion increases more rapidly than fluid velocity.At low velocities in interstices, transverse dispersion is characterized by a region in which transverse diffusion dominates. If the fluid velocity gets high enough, there will be a transition into a region where there is stream splitting with mass transfer but with insufficient residence time to completely damp-out concentration variations within pore spaces.There are several variables that must be controlled to get consistent longitudinal and transverse dispersion results, viz.,edge effect in packed tubes,particle size distribution,particle shape,packing or permeability heterogeneities,viscosity ratios,gravity forces,amount of turbulence, andeffect of an immobile phase. Introduction Diffusion and dispersion in porous rocks are of current interest to the oil industry. This interest arises because of the influence of dispersion on miscible-displacement processes.In a recovery process utilizing a zone of miscible fluid, there is the possibility of losing miscibility by dissipating the miscible fluid or by channeling or ‘fingering" through the miscible zone. Diffusion and dispersion are two of the mechanisms that may lead to mixing and dissipation of the slug. On the other hand, dispersion may tend to damp-out viscous fingers which may be channeling through the miscible slug. Hence, dispersion may be detrimental or beneficial (if it prevents fingering through the miscible zone). Therefore, it is doubly important that we understand these processes.In this paper we review, summarize and interpret a great deal of information from the literature. In particular, we will briefly discuss molecular diffusion in miscible fluids. Then we will discuss what differences to expect for diffusion in a porous rock. If there is movement of the fluid through the rock, then there may be an additional mixing or "dispersion". Furthermore, the dispersion longitudinally (in the direction of gross fluid movement) and transverse to the direction of fluid movement will not be equal. We will discuss both types of dispersion as well as several variables which can affect dispersion (viscosity differences, density differences, turbulence, heterogeneity of media, etc.). This group of variables has sometimes led to difficulty when comparing literature data. DIFFUSION OF MISCIBLE FLUIDS If two miscible fluids are in contact, with an initially sharp interface, they will slowly diffuse into one another. SPEJ P. 70^

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Convection Currents in a Porous Medium

1945-06-01

C. W. Horton , F. T. Rogers

The problem is considered of the convection of a fluid through a permeable medium as the result of a vertical temperature-gradient, the medium being in the shape of a flat … The problem is considered of the convection of a fluid through a permeable medium as the result of a vertical temperature-gradient, the medium being in the shape of a flat layer bounded above and below by perfectly conducting media. It appears that the minimum temperature-gradient for which convection can occur is approximately 4π2h2μ/kgρ0α D2, where h2 is the thermal diffusivity, g is the acceleration of gravity, μ is the viscosity, k is the permeability, α is the coefficient of cubical expansion, ρ0 is the density at zero temperature, and D is the thickness of the layer; this exceeds the limiting gradient found by Rayleigh for a simple fluid by a factor of 16D2/27π2kρ0. A numerical computation of this gradient, based upon the data now available, indicates that convection currents should not occur in such a geological formation as the Woodbine sand of East Texas (west of the Mexia Fault zone); in view of the fact, however, that the distribution of NaCl in this formation seems to require the existence of convection currents, and in view of the approximations involved in applying the present theory, it seems safe tentatively, to conclude that convection currents do exist in this formation and that the expression given above predicts excessive minimum gradients when applied to such a formation.

Pore-scale imaging and modelling

2012-04-04

Martin J. Blunt , Branko Bijeljic , Hu Dong +5 more

Pore-scale imaging and modelling – digital core analysis – is becoming a routine service in the oil and gas industry, and has potential applications in contaminant transport and carbon dioxide … Pore-scale imaging and modelling – digital core analysis – is becoming a routine service in the oil and gas industry, and has potential applications in contaminant transport and carbon dioxide storage. This paper briefly describes the underlying technology, namely imaging of the pore space of rocks from the nanometre scale upwards, coupled with a suite of different numerical techniques for simulating single and multiphase flow and transport through these images. Three example applications are then described, illustrating the range of scientific problems that can be tackled: dispersion in different rock samples that predicts the anomalous transport behaviour characteristic of highly heterogeneous carbonates; imaging of super-critical carbon dioxide in sandstone to demonstrate the possibility of capillary trapping in geological carbon storage; and the computation of relative permeability for mixed-wet carbonates and implications for oilfield waterflood recovery. The paper concludes by discussing limitations and challenges, including finding representative samples, imaging and simulating flow and transport in pore spaces over many orders of magnitude in size, the determination of wettability, and upscaling to the field scale. We conclude that pore-scale modelling is likely to become more widely applied in the oil industry including assessment of unconventional oil and gas resources. It has the potential to transform our understanding of multiphase flow processes, facilitating more efficient oil and gas recovery, effective contaminant removal and safe carbon dioxide storage.

Extending Predictive Capabilities to Network Models

1998-12-01

P. E. Øren , S. Bakke , Ole Jakob Arntzen

Summary We reconstruct three-dimensional (3D) sandstone models that give a realistic description of the complex pore space observed in actual sandstones. The reconstructed pore space is transformed into a pore … Summary We reconstruct three-dimensional (3D) sandstone models that give a realistic description of the complex pore space observed in actual sandstones. The reconstructed pore space is transformed into a pore network that is used as input to a two-phase network model. The model simulates primary drainage and water injection on the basis of a physical scenario for wettability changes at the pore level. We derive general relationships among pore structure, wettability, and capillary pressure for the different pore level displacement mechanisms that may occur in the network model. We present predicted transport properties for three different reconstructed sandstones of increasing complexity: Fontainebleau, a water-wet Bentheimer, and a mixed-wet reservoir rock. Predicted transport properties are in good agreement with available experimental data. For the reservoir rock, both the experiments and the simulated results show that continuous oil films allow low oil saturations to be reached during forced water injection. However, the oil relative permeability is very low.

The drainage of thin liquid films between solid surfaces

1985-11-15

Derek Y. C. Chan , Roger G. Horn

We present measurements of the thickness as a function of time of liquid films as they are squeezed between molecularly smooth mica surfaces. Three Newtonian, nonpolar liquids have been studied: … We present measurements of the thickness as a function of time of liquid films as they are squeezed between molecularly smooth mica surfaces. Three Newtonian, nonpolar liquids have been studied: octamethylcyclotetrasiloxane, n-tetradecane, and n-hexadecane. The film thicknesses are determined with an accuracy of 0.2 nm as they drain from ∼1 μm to a few molecular layers. Results are in excellent agreement with the Reynolds theory of lubrication for film thicknesses above 50 nm. For thinner films the drainage is slower than the theoretical prediction, which can be accounted for by assuming that the liquid within about two molecular layers of each solid surface does not undergo shear. In very thin films the continuum Reynolds theory breaks down, as drainage occurs in a series of abrupt steps whose size matches the thickness of molecular layers in the liquid. The presence of trace amounts of water has a dramatic effect on the drainage of a nonpolar liquid between hydrophilic surfaces, causing film rupture which is not observed in the dry liquids.

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Review of ASP EOR (alkaline surfactant polymer enhanced oil recovery) technology in the petroleum industry: Prospects and challenges

2014-10-12

Abass A. Olajire

Response of a finite‐diameter well to an instantaneous charge of water

1967-03-01

Hilton H. Cooper , John Bredehoeft , Istavros S. Papadopulos

A solution is presented for the change in water level in a well of finite diameter after a known volume of water is suddenly injected or withdrawn. A set of … A solution is presented for the change in water level in a well of finite diameter after a known volume of water is suddenly injected or withdrawn. A set of type curves computed from this solution permits a determination of the transmissibility of the aquifer.

Gas Diffusion in Porous Media

1959-07-10

R. J. Millington

A method has been proposed for deriving a characteristic determining flow in porous systems. This characteristic combines both area and path-length factors used by earlier authors. For a gas, diffusive … A method has been proposed for deriving a characteristic determining flow in porous systems. This characteristic combines both area and path-length factors used by earlier authors. For a gas, diffusive flow is proportional to the 4/3 power of the gas-filled porosity, and this function has been derived from consideration of the planar distribution of spherical pores and the interaction of two adjacent planes.

Recent Advances in Surfactant EOR

2011-07-07

George J. Hirasaki , Clarence A. Miller , Maura Puerto

Summary In this paper, recent advances in surfactant enhanced oil recovery (EOR) are reviewed. The addition of alkali to surfactant flooding in the 1980s reduced the amount of surfactant required, … Summary In this paper, recent advances in surfactant enhanced oil recovery (EOR) are reviewed. The addition of alkali to surfactant flooding in the 1980s reduced the amount of surfactant required, and the process became known as alkaline/surfactant/polymer flooding (ASP). It was recently found that the adsorption of anionic surfactants on calcite and dolomite can also be significantly reduced with sodium carbonate as the alkali, thus making the process applicable for carbonate formations. The same chemicals are also capable of altering the wettability of carbonate formations from strongly oil-wet to preferentially water-wet. This wettability alteration in combination with ultralow interfacial tension (IFT) makes it possible to displace oil from preferentially oil-wet carbonate matrix to fractures by oil/water gravity drainage. The alkaline/surfactant process consists of injecting alkali and synthetic surfactant. The alkali generates soap in situ by reaction between the alkali and naphthenic acids in the crude oil. It was recently recognized that the local ratio of soap/surfactant determines the local optimal salinity for minimum IFT. Recognition of this dependence makes it possible to design a strategy to maximize oil recovery with the least amount of surfactant and to inject polymer with the surfactant without phase separation. An additional benefit of the presence of the soap component is that it generates an oil-rich colloidal dispersion that produces ultralow IFT over a much wider range of salinity than in its absence. It was once thought that a cosolvent such as alcohol was necessary to make a microemulsion without gel-like phases or a polymer-rich phase separating from the surfactant solution. An example of an alternative to the use of alcohol is to blend two dissimilar surfactants: a branched alkoxylated sulfate and a double-tailed, internal olefin sulfonate. The single-phase region with NaCl or CaCl2 is greater for the blend than for either surfactant alone. It is also possible to incorporate polymer into such aqueous surfactant solutions without phase separation under some conditions. The injected surfactant solution has underoptimum phase behavior with the crude oil. It becomes optimum only as it mixes with the in-situ-generated soap, which is generally more hydrophobic than the injected surfactant. However, some crude oils do not have a sufficiently high acid number for this approach to work. Foam can be used for mobility control by alternating slugs of gas with slugs of surfactant solution. Besides effective oil displacement in a homogeneous sandpack, it demonstrated greatly improved sweep in a layered sandpack.

Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions Ca2+, Mg2+, and SO42−

2006-12-23

Peimao Zhang , Medad T. Tweheyo , Tor Austad

Enhanced Oil Recovery: An Update Review

2010-08-27

Vladimir Alvarado , Eduardo Manrique

With the decline in oil discoveries during the last decades it is believed that EOR technologies will play a key role to meet the energy demand in years to come. … With the decline in oil discoveries during the last decades it is believed that EOR technologies will play a key role to meet the energy demand in years to come. This paper presents a comprehensive review of EOR status and opportunities to increase final recovery factors in reservoirs ranging from extra heavy oil to gas condensate. Specifically, the paper discusses EOR status and opportunities organized by reservoir lithology (sandstone and carbonates formations and turbiditic reservoirs to a lesser extent) and offshore and onshore fields. Risk and rewards of EOR methods including growing trends in recent years such as CO2 injection, high pressure air injection (HPAI) and chemical flooding are addressed including a brief overview of CO2-EOR project economics.

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On the Stability, or Instability, of certain Fluid Motions

1879-11-01

Lord Rayleigh

Salinity, Temperature, Oil Composition, and Oil Recovery by Waterflooding

1997-11-01

Guiqian Tang , Norman R. Morrow

Summary The effect of aging and displacement temperatures and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This … Summary The effect of aging and displacement temperatures and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea sandstone with three crude oils and three reservoir brines (RB's). Salinity was varied by changing the concentration of total dissolved solids (TDS's) of the synthetic brine in proportion. Salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the RB with dilution of both the initial (connate) and invading brine or dilution of either. Aging and displacement temperatures were varied independently. For all crude oils, water wetness and oil recovery increased with increase in displacement temperature. Removal of light components from the crude oil resulted in increased water wetness. Addition of alkanes to the crude oil reduced the water wetness, and increased oil recovery. Relationships between waterflood recovery and rate and extent of oil recovery by spontaneous imbibition are summarized.

Wettability and Its Effect on Oil Recovery

1990-12-01

Norman R. Morrow

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics … Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Introduction Reservoir wettability is determined by complex interface boundary conditionsacting within the pore space of sedimentary rocks. These conditions have adominant effect on interface movement and associated oil displacement. Wettability is a significant issue in multiphase flow problems ranging from oilmigration from source rocks to such enhanced recovery processes as alkalineflooding or alternate injection of CO2 and water. In this paper, wettabilitywill be discussed mainly in the context of recovery of light (low-viscosity)oils by waterflooding. Waterflooding has been widely applied for more than halfa century; secondary recovery by waterflooding presently accounts for more thanone-half of current U.S. oil production. Many research papers have addressedthe effect of wettability on waterflood recovery during this period. For muchof the past 50 years, however, a large body of reservoir period. For much ofthe past 50 years, however, a large body of reservoir engineering practice hasbeen based on the assumption that most reservoirs are very strongly water-wet(VSWW); i.e., the reservoir-rock source always maintains a strong affinity forwater in the presence of oil. The rationale for assuming VSWW conditions wasthat water originally occupied the reservoir trap; as oil accumulated, waterwas retained by capillary forces in the finer pore spaces and as films on poresurfaces overlain by oil. Wettability behavior other than VSWW was observed forreservoir core samples, but was often ascribed to artifacts related to corerecovery and testing procedures. The majority of reservoir engineeringmeasurements have been made on cleaned core with refined oil or air as thenonwetting phase to give results for, or equivalent to, VSWW conditions. Examples of such measurements are laboratory waterfloods, determination ofelectrical resistivity vs. water saturation relationships, and capillarypressure measurements for determination of reservoir connate water saturation. Mounting evidence on the effects of crude oil on wetting behavior has now ledto wide acceptance of the conclusion that most reservoirs are at wettabilityconditions other than VSWW. This conclusion has led to a resurgence of interestin satisfactory procedures for measuring reservoir wettability and determiningits effect procedures for measuring reservoir wettability and determining itseffect on oil recovery, especially with respect to waterflooding. Determinationof reservoir wettability and its effect on oil recovery by methods that involvecore samples will be referred to as advanced core analysis for wettability(ACAW). Reservoir wettability is not a simply defined property. Classificationof reservoirs as water-wet or oil-wet is a gross oversimplification. Variousprocedures for measuring wettability have been proposed. Two methods ofquantifying wettability based on rock/brine/oil displacement behavior, themodified Amott test and the USBM test, are in common use. Each method dependson water saturation measurements and related capillary pressures or flowconditions to define a wettability scale. The tests show pressures or flowconditions to define a wettability scale. The tests show that reservoirwettability can cover a broad spectrum of wetting conditions that range fromVSWW to very strongly oil-wet. Within this range, complex mixed-wettabilityconditions given by combinations of preferentially water-wet and oil-wetsurfaces have been identified. In preferentially water-wet and oil-wet surfaceshave been identified. In this paper, the adopted scales of reservoirwettability and their relationships to interface boundary conditions areconsidered together with the dramatic effects that wettability can have on oilrecovery. Contact Angles, Spreading and Adhesion Contact Angle and Spreading. Contact angle is the most universal measure ofthe wettability of surfaces. Fig. 1 shows idealized examples of contact anglesat smooth solid surfaces for oil and water of matched density. Early studies ofwetting phenomena showed that the wetting properties of a solid are dominatedby the outermost layer of molecules. (Films that result from spreading andother thin adsorbed films are not indicated in Fig. 1.) Large change in thewettability of a surface, such as quartz, can be achieved by adsorption of amonolayer of polar molecules so that the outermost part of the surface iscomposed of hydrocarbon chains. Extreme change in wettability (see Fig. 1), such as from a or b to e or f, or vice versa, is called wettability reversal. Adsorption of polar compounds from crude oil plays a critical role indetermining the wetting properties of reservoir-rock surfaces. Many earlystudies of wetting behavior, even for comparatively simple systems, wereplagued by problems of reproducibility. Aside from surface contamination, otherforms of heterogeneity in chemical composition, surface roughness, and staticand dynamic interface properties contribute to the complexity of observedwetting phenomena. Large differences in contact angles, depending on whether aninterface was advanced or receded, called into question the validity ofattempting to describe wettability by a single-valued equilibrium contactangle. Successful systematic studies of closely reproducibleequilibrium-contact-angle measurements have been summarized by Zisman. By useof smooth (often polymeric), solid surfaces and pure liquids, contact-anglehysteresis was limited to within 1 or 20. In contrast, contact-angle hysteresisis observed almost invariably for crude-oil/brine systems. Fig. 2 showsexamples of contact angles that exhibit small and large hysteresis. Recedingangles are generally low (less than 30 degrees) and seldom exceed 60 degrees, whereas a wide range of advancing angles is observed. The shaded regions inFig. 2 show the range of possible contact-angle values for a fixed position ofthe three-phase line of contact. Contact-angle measurements onreservoir-crude-oil/brine systems provide one approach to measuring reservoirwettability. For the most extensive set of data yet reported, contact anglesfor crude oil and simulated reservoir brine were measured at reservoirtemperature and ambient pressure. Choice of mineral substrate, usually quartzor calcite, was pressure. Choice of mineral substrate, usually quartz orcalcite, was based on what was judged from petrographic examination to be thepredominant mineral at pore surfaces. (There are obvious limitations topredominant mineral at pore surfaces. (There are obvious limitations torepresenting the rock surface by a single mineral.) JPT P. 1476

Chemical evolution and mineral deposition in boiling hydrothermal systems

1985-02-01

S. E. Drummond , Hiroshi Ohmoto

A thermodynamic model of boiling hydrothermal solutions is developed and applied over a wide range of physical and chemical conditions. Within the range of conditions observed in natural boiling hydrothermal … A thermodynamic model of boiling hydrothermal solutions is developed and applied over a wide range of physical and chemical conditions. Within the range of conditions observed in natural boiling hydrothermal systems the processes of liquid-vapor partitioning and the resultant effects on mineral solubilities are highly varied and complex. Metals that are complexed by chloride are deposited largely as a result of the decreasing proton concentration associated with CO 2 exsolution during boiling. Metal bisulfide complexes are destabilized most when the decrease in proton concentration is sluggish relative to the loss of H 2 S.Vaporization of only a few percent of a solution can decrease the proton concentration by several orders of magnitude when the CO 2 /H (super +) and CO 2 /Sigma SO 4 concentration ratios are initially high. The relationship between the proton, CO 2 , and Sigma SO 4 concentrations prior to boiling to the proton concentration after boiling is defined explicitly by a few simple equations. These equations along with the solubilities of calcite and anhydrite constitute the chemical boundary conditions for significant mineral deposition by boiling. Typical hydrothermal fluids lose most of their volatile components to the vapor phase and most of their metals to mineral phases by the time boiling has proceeded to the point where the volumes of the vapor and liquid phases are equal.Physical variables such as the heat budget and the restrictions on the partitioning of mass between liquid and vapor, although significant, are subordinate to the compositional variables in determining the chemical evolution of a boiling hydrothermal solution. Mineral deposition is most vigorous when the volatile components partition from the solution to the vapor phase in a manner resembling perfect fractional (Rayleigh) distillation. As temperature decreases, the efficiency of boiling for depositing metals from solution increases, and the amount of metals in solution typically decreases such that the net effect of boiling is most favorable for ore formation at temperatures around 300 degrees C. Mineral and metal complex stoichiometries in combination with the relative volatilities of CO 2 and H 2 S determine the general sequence of mineral deposition during boiling. These major variables, many other minor variables, and the multiple interactions thereof are accounted for rigorously. The amount and paragenesis of ore and gangue minerals deposited by boiling are presented for numerous hypothetical hydrothermal systems. Analysis of these results suggests that boiling is perhaps the most generally effective ore depositional mechanism at the conditions operative in many boiling hydrothermal systems.

Numerical models and experiments on immiscible displacements in porous media

1988-04-01

R. Lenormand , Éric Touboul , C. Zarcone

Immiscible displacements in porous media with both capillary and viscous effects can be characterized by two dimensionless numbers, the capillary number C , which is the ratio of viscous forces … Immiscible displacements in porous media with both capillary and viscous effects can be characterized by two dimensionless numbers, the capillary number C , which is the ratio of viscous forces to capillary forces, and the ratio M of the two viscosities. For certain values of these numbers, either viscous or capillary forces dominate and displacement takes one of the basic forms: (a) viscous fingering, (b) capillary fingering or (c) stable displacement. We present a study in the simple case of injection of a non-wetting fluid into a two-dimensional porous medium made of interconnected capillaries. The first part of this paper presents the results of network simulators (100 × 100 and 25 × 25 pores) based on the physical rules of the displacement at the pore scale. The second part describes a series of experiments performed in transparent etched networks. Both the computer simulations and the experiments cover a range of several decades in C and M . They clearly show the existence of the three basic domains (capillary fingering, viscous fingering and stable displacement) within which the patterns remain unchanged. The domains of validity of the three different basic mechanisms are mapped onto the plane with axes C and M , and this mapping represents the ‘phase-diagram’ for drainage. In the final section we present three statistical models (percolation, diffusion-limited aggregation (DLA) and anti-DLA) which can be used for describing the three ‘basic’ domains of the phase-diagram.

Enhanced Oil Recovery - An Overview

2007-10-29

Sara Thomas

Nearly 2.0 × 1012 barrels (0.3 × 1012 m3) of conventional oil and 5.0 × 1012 barrels (0.8 × 1012 m3) of heavy oil will remain in reservoirs worldwide after … Nearly 2.0 × 1012 barrels (0.3 × 1012 m3) of conventional oil and 5.0 × 1012 barrels (0.8 × 1012 m3) of heavy oil will remain in reservoirs worldwide after conventional recovery methods have been exhausted. Much of this oil would be recovered by Enhanced Oil Recovery (EOR) methods, which are part of the general scheme of Improved Oil Recovery (IOR). The choice of the method and the expected recovery depends on many considerations, economic as well as technological. This paper examines the EOR methods that have been tested in the field. Some of these have been commercially successful, while others are largely of academic interest. The reasons for the same are discussed. The paper examines thermal and non-thermal oil recovery methods. These are presented in a balanced fashion, with regard to commercial success in the field. Only a few recovery methods have been commercially successful, such as steam injection based processes in heavy oils and tar sands (if the reservoir offers favourable conditions for such applications) and miscible carbon dioxide for light oil reservoirs. Other recovery methods have been tested, and even produced incremental oil, but they have inherent limitations. The current EOR technologies are presented in a proper perspective, pointing out the technical reasons for the lack of success. Methods for improving oil recovery, in particular those concerned with lowering the interstitial oil saturation, have received a great deal of attention both in the laboratory and in the field. From the vast amount of literature on the subject, one gets the impression that it is relatively simple to increase oil recovery beyond secondary (assuming that the reservoir lends itself to primary and secondary recovery). It is shown that this is not the case. Many reservoirs suitable for steam injection and carbon dioxide have already been exploited and are approaching maturity. Other EOR methods suffer from limitations that have little to do with economics. Recovering incremental oil is complex and costly, and has been successful only for a few processes under exacting conditions. Nevertheless, EOR will continue to have an important place in oil production, in view of the escalating energy demand and the tight supply. It is suggested that much research is needed to develop technologies for recovering over two-thirds of the oil that will remain unrecovered in reservoirs. Key references are indicated.

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The Instability of Slow, Immiscible, Viscous Liquid-Liquid Displacements in Permeable Media

1959-12-01

R.L. Chuoke , Patrick Meurs , Chris van der Poel

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 188–194. Introduction The purposes of this paper are to present theoretical and experimental evidence for occurrence of macroscopic instabilities in displacement … Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 188–194. Introduction The purposes of this paper are to present theoretical and experimental evidence for occurrence of macroscopic instabilities in displacement of one viscous fluid by another immiscible with it through a uniform porous medium and to compare available experimental data with some predictions of a theory of instability developed by the first author. The instabilities are referred to as macroscopic in the sense that spatially quasi-sinusoidal, growing fingers of the displacing liquid are formed, the width and peak-to-peak separation (wavelength) of which is large relative to a characteristic length of the particular permeable medium such as grain size. Visual models of two kinds have been used to obtain observations: displacement of oil by water-glycerine solutions through the flow channel formed by closely spaced parallel plates and displacement of oil by water with and without initial interstitial water through unconsolidated glass powder packs, employing the technique of matching indices of refraction. In all cases we have observed macroscopic instabilities or fingers under conditions predicted by the theory to be favorable for their occurrence. The phenomenon discussed here is not the production of streamers due to gross inhomogeneities such as permeability stratification of the porous medium.It is our object to show, on the contrary, that a quantitative prediction of finger spacing is possible in a porous medium known to be macroscopically homogeneous and isotropic throughout. The importance of the phenomenon in its influence on the configuration of oil and water with respect to oil production behavior was noted earlier by Engelberts and Klinkenberg who coined the term "viscous fingering". Theory Necessary and Sufficient Conditions for Instability and Initial Kinematics There are several levels of increasing complexity in the theoretical description of instability of fluid displacements in permeable media. Of these, the simplest description, adapted to low permeability systems, is selected for presentation. More inclusive descriptions are reserved for separate publication.

Observations Relating to the Wettability of Porous Rock

1959-12-01

Earl Amott

Published in Petroleum Transactions, AIME, Vol. 216, 1959, pages 156–162.Paper presented at Fall Meeting of Los Angeles Basin Section in Los Angeles, Calif., Oct. 16–17, 1958. Abstract A test is … Published in Petroleum Transactions, AIME, Vol. 216, 1959, pages 156–162.Paper presented at Fall Meeting of Los Angeles Basin Section in Los Angeles, Calif., Oct. 16–17, 1958. Abstract A test is described in which the wettability of porous rock is measured as a function of the displacement properties of the rock-water-oil system. Four displacement operations are carried out:spontaneous displacement of water by oil,forced displacement of water by oil in the same system using a centrifuging procedure,spontaneous displacement of oil by water, andforced displacement of oil by water. Ratios of the spontaneous displacement volumes to the total displacement volumes are used as wettability indices.Cores having clean mineral surfaces (strongly preferentially water-wet) show displacement-by-water ratios approaching 1.00 and displacement-by-oil ratios of zero. Cores which are strongly preferentially oil-wet give the reverse results. Neutral wettability cores show zero values for both ratios. Fresh cores from different oil reservoirs have shown wettabilities in this test covering almost the complete range of the test. However, most of the fresh California cores tested were slightly preferentially water-wet. The changes in core wettabilities, as indicated by this test, resulting from various core handling procedures were observed. In some cases the wettabilities of fresh cores were changed by drying or by extracting with toluene or dioxane; in other cases they were not changed. Contact of cores with filtrates from water-base drilling muds caused little change in wettability while contact with filtrates from oil-base muds decreased the preference of the cores for water. Using this test to evaluate wettability, a study was made of the correlation of wettability with waterflood oil recovery for outcrop Ohio sandstone and for Alundum. Results indicate that no single correlation between these factors applies to different porous rock systems. It is thought that differences in pore geometry result in differences in this correlation.

Physical Chemistry of Surfaces

1979-01-01

Shmuel Yariv , Harold Cross

Theory of Propagation of Elastic Waves in a Fluid-Saturated Porous Solid. II. Higher Frequency Range

1956-03-01

M. A. Biot

The theory of propagation of stress waves in a porous elastic solid developed in Part I for the low-frequency range is extended to higher frequencies. The breakdown of Poiseuille flow … The theory of propagation of stress waves in a porous elastic solid developed in Part I for the low-frequency range is extended to higher frequencies. The breakdown of Poiseuille flow beyond the critical frequency is discussed for pores of flat and circular shapes. As in Part I the emphasis of the treatment is on cases where fluid and solids are of comparable densities. Dispersion curves for phase and group velocities along with attenuation factors are plotted versus frequency for the rotational and the two dilational waves and for six numerical combinations of the characteristic parameters of the porous systems. Asymptotic behavior at high frequency is also discussed.

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Polymer-Improved Oil Recovery

1991-01-01

K. S. Sorbie

In-situ heavy and extra-heavy oil recovery: A review

2016-08-20

Kun Guo , Hailong Li , Zhixin Yu

The Network Model of Porous Media

1956-12-01

Irving Fatt

Published in Petroleum Transactions, AIME, Volume 207, 1956, pages 144–181.Capillary Pressure CharacteristicsDynamic Properties of a Single Size Tube NetworkDynamic Properties of Networks With Tube Radius Distribution Abstract This paper proposes … Published in Petroleum Transactions, AIME, Volume 207, 1956, pages 144–181.Capillary Pressure CharacteristicsDynamic Properties of a Single Size Tube NetworkDynamic Properties of Networks With Tube Radius Distribution Abstract This paper proposes the network of tubes as a model more closely representing real porous media than does the bundle of tubes. Capillary pressure curves are derived from network models and pore size distributions are calculated from these curves. In this way is shown the difference between the true and calculated pore size distributions when the capillary pressure curve is used to obtain pore size distribution for porous media. Introduction Despite the technological importance of the laws governing flow through porous media, many of these laws have not yet been clearly formulated. This is especially true of the laws governing multiphase flow. The static properties, such as the capillary pressure curve, are also not at present interpretable correctly in terms of the pore size distribution and other structural properties of porous media. In the absence of any well founded theoretical description of fluid flow through porous media, many empirical descriptions have been proposed. In addition to the strictly empirical flow equations, some equations have been developed rigorously from simple geometrical models of the pore spaces. These equations are only as valid as is the model used in their development. The two models used in the past, the sphere pack and the bundle of tubes, have been too simple, and as a result, the equations derived from them have failed to predict the observed properties. Agreement between theory and observation has been achieved for these models by inserting parameters of doubtful physical significance.

Surfactant Adsorption Isotherms: A Review

2021-11-24

Shams Kalam , Sidqi A. Abu-Khamsin , Muhammad Shahzad Kamal +1 more

The need to minimize surfactant adsorption on rock surfaces has been a challenge for surfactant-based, chemical-enhanced oil recovery (cEOR) techniques. Modeling of adsorption experimental data is very useful in estimating … The need to minimize surfactant adsorption on rock surfaces has been a challenge for surfactant-based, chemical-enhanced oil recovery (cEOR) techniques. Modeling of adsorption experimental data is very useful in estimating the extent of adsorption and, hence, optimizing the process. This paper presents a mini-review of surfactant adsorption isotherms, focusing on theories of adsorption and the most frequently used adsorption isotherm models. Two-step and four-region adsorption theories are well-known, with the former representing adsorption in two steps, while the latter distinguishes four regions in the adsorption isotherm. Langmuir and Freundlich are two-parameter adsorption isotherms that are widely used in cEOR studies. The Langmuir isotherm is applied to monolayer adsorption on homogeneous sites, whereas the Freundlich isotherm suites are applied to multilayer adsorption on heterogeneous sites. Some more complex adsorption isotherms are also discussed in this paper, such as Redlich-Peterson and Sips isotherms, both involve three parameters. This paper will help select and apply a suitable adsorption isotherm to experimental data.

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Fundamentals of Enhanced Oil Recovery

2014-01-01

Larry W. Lake , Russell T. Johns , W. R. Rossen +1 more

A revision of the 1989 classic, Enhanced Oil Recovery by Larry Lake, this text, Fundamentals of Enhanced Oil Recovery, retains the original work's emphasis on fractional flow theory and phase … A revision of the 1989 classic, Enhanced Oil Recovery by Larry Lake, this text, Fundamentals of Enhanced Oil Recovery, retains the original work's emphasis on fractional flow theory and phase behavior to explain enhanced oil recovery (EOR) processes. There is additional coverage on cutting edge (or current) topics, such as low-salinity EOR, steam-assisted gravity drainage, and expanded coverage on thermodynamics and foam EOR. With its frequent reinforcement of two fundamental EOR principles, lowering the mobility ratio and increasing the capillary number, it is an excellent resource for undergraduate classes. Errata (http://go.spe.org/FEORerrata)

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Improved Oil Recovery by Surfactant and Polymer Flooding

1977-01-01

Kansas City Polymer Flooding , D. O. Shah , R. S. Schechter

Synthesis and Mechanistic Study of a Copolymer Demulsifier for Dehydration of Water‐in‐Oil Emulsion of Crude Oil

2025-06-25

Xue-Zhi Li , Bin Ma , Liming Fu +3 more | ChemistryOpen

This study presents the synthesis and characterization of a novel polymeric demulsifier, P(AM‐EHMA‐VBS‐VP), through emulsion polymerization for efficient separation of water‐in‐crude oil emulsions. The synthesis parameters are systematically optimized using … This study presents the synthesis and characterization of a novel polymeric demulsifier, P(AM‐EHMA‐VBS‐VP), through emulsion polymerization for efficient separation of water‐in‐crude oil emulsions. The synthesis parameters are systematically optimized using orthogonal array design complemented by single‐factor experiments. The demulsification performance is evaluated under simulated field conditions, with particular emphasis on dosage optimization and temperature effects. Comprehensive mechanistic investigations are conducted through dynamic interfacial tension measurements, interfacial dilational rheology analysis, and zeta potential characterization to elucidate the demulsification mechanism and the impact of inorganic salts on demulsification efficiency. The optimized synthesis conditions yield a copolymer with monomer mass ratios of AM:EHMA:VBS:VP = 1:4:4:1, achieved at 60 °C for 8 h with 30% monomer concentration and 0.15% initiator dosage. Optimal demulsification performance is observed at 80 °C with a demulsifier concentration of 300 mg L −1 . The synthesized demulsifier demonstrates remarkable salt tolerance, maintaining effectiveness in environments containing up to 30 000 mg L −1 NaCl and 10 000 mg L −1 CaCl 2 . Mechanistic studies reveal that the demulsifier operates through interfacial adsorption, which simultaneously reduces the mechanical strength of the interfacial film and decreases the surface charge density of emulsion droplets. This dual mechanism effectively compromises the emulsion stability by diminishing both the film's resistance to deformation and the electrostatic repulsion between droplets.

Comprehensive Displacement System Utilizing Dispersed Particle Gels Coupling Viscosity Reduction and Breakthrough Channel Control for Heavy Oil Cold Production

2025-06-24

Ning Yang , Zhaokai Wang , Yiran Li +4 more | Energy & Fuels

Comprehensive experimental analysis of electromagnetic field effects on enhanced oil recovery through optimized magnetic field-induced fluid dynamics

2025-06-24

Elnur Alizade | Kazakhstan journal for oil & gas industry

Background: The behavior of reservoir fluids under the influence of magnetic fields has significant implications for fluid transport and enhanced oil recovery. This study investigates the electrokinetic properties of reservoir … Background: The behavior of reservoir fluids under the influence of magnetic fields has significant implications for fluid transport and enhanced oil recovery. This study investigates the electrokinetic properties of reservoir fluids and fluid discharge behavior under varying pressure conditions in the presence of magnetic fields. Aim: The primary aim of this study is to investigate the effects of magnetic fields on the electrokinetic properties of reservoir fluids and their fluid discharge behavior under varying pressure conditions. By conducting comprehensive experimental analyses, the research seeks to determine the optimal magnetic field intensity that enhances fluid conductivity, ion mobility and water displacement efficiency. The study also aims to evaluate the role of magnetic fields in mitigating pressure-induced compaction in porous media and establishing stable fluid flow conditions. The findings are expected to contribute to the advancement of enhanced oil recovery (EOR) techniques by integrating magnetic field technology to optimize oil field development, particularly in mature and low-permeability reservoirs. Materials and methods: A custom experimental setup, including a high-pressure column, PVT bomb, electromagnet, measurement and control devices was developed to simulate reservoir conditions. Magnetic field intensities ranging from 40 to 150 mT were applied to study their effects on voltage, resistance, and water discharge during pressure variations (1.6–14.4 atm). Results: The application of magnetic fields significantly enhanced the electrokinetic properties of reservoir fluids. At an optimal intensity of 125 mT, ion mobility and fluid conductivity were maximized, leading to a peak water discharge volume of approximately 75 m³ at 8–9 atm. Beyond this pressure, a dynamic equilibrium stabilized fluid flow. Resistance and voltage values decreased substantially under magnetic fields, highlighting their role in mitigating pressure-induced compaction in porous media. Conclusion: This study demonstrates the transformative effects of magnetic fields on the electrokinetic properties and discharge behavior of reservoir fluids. The optimal magnetic field intensity of 125 mT enhanced ion mobility, fluid conductivity and water discharge, achieving a peak discharge volume of approximately 75 m³ at 8–9 atm. These findings emphasize the role of magnetic fields in reducing flow resistance and stabilizing fluid flow under high-pressure conditions, particularly by mitigating pressure-induced compaction in porous media. Additionally, the observed dynamic equilibrium beyond 8 atm suggests that magnetic fields can maintain fluid conductivity and discharge stability despite increasing pressures. These advancements pave the way for employing magnetic field technology to enhance oil recovery, especially in challenging environments such as mature or low-permeability reservoirs.

Hot-Water Flooding Performance Assessment in Heterogeneous Reservoirs through Numerical Simulation

2025-06-24

Md Irshad Ansari , G. Suresh Kumar | Journal of Energy Engineering

Molecular dynamics simulation of crude oil detachment using ScCO2 and miscible agents on SiO2 surfaces

2025-06-24

Congying Lu , Yue Zhao , Zhenyu Yuan +4 more | Journal of Molecular Modeling

Applications of nanoparticle in enhanced oil recovery: A comprehensive review, history, and future prospects

2025-06-23

Ali Akbari , Hamed Nikravesh , Yousef Kazemzadeh | The Canadian Journal of Chemical Engineering

Abstract Oil extraction methods are categorized into three main stages: primary, secondary, and tertiary enhanced oil recovery (EOR). In the tertiary stage, techniques such as chemical injection, thermal injection, and … Abstract Oil extraction methods are categorized into three main stages: primary, secondary, and tertiary enhanced oil recovery (EOR). In the tertiary stage, techniques such as chemical injection, thermal injection, and dissolved gas injection are employed, with nanoparticles providing innovative solutions. Following primary and secondary recovery processes, more than 50% of the total oil volume remains trapped in reservoirs, highlighting the significance of EOR. Nanoparticles, ranging from 1 to 100 nanometres, enhance EOR through mechanisms such as permeability control, interfacial tension reduction, and mass transfer improvement. Among the nanoparticles studied, silica nanoparticles have shown extensive potential due to their stability and ability to alter reservoir wettability. These nanoparticles, along with others such as magnesium oxide, aluminium oxide, zinc oxide, and iron oxide, can increase the recovery factor by up to 20% by altering wettability, decreasing interfacial tension, and improving mobility control. The application of nanotechnology in the oil industry spans from exploration to refining, enhancing processes with nanomaterials such as solid compounds, complex fluids, and nanoparticle mixtures. Challenges include the high cost of chemicals and environmental concerns. The use of nanoparticles, particularly silica nanoparticles, in EOR demonstrates significant potential for improving oil extraction methods; however, it faces challenges in maximizing oil recovery while minimizing negative environmental impacts. Future research should focus on the application of nanotechnology in EOR to develop methods that are both effective and environmentally sustainable. Balancing efficiency and environmental responsibility are essential for advancing toward a cleaner and more efficient oil industry.

Optimization of the Application of Carbon Dioxide Flooding Enhanced Oil Recovery Technology in High-temperature and High-Pressure Reservoirs

2025-06-23

Bo Ren | Academic Journal of Science and Technology

In this paper, in view of the development problems of high-temperature and high-pressure reservoirs, the application optimization strategies of carbon dioxide flooding enhanced oil recovery technology are systematically discussed. Through … In this paper, in view of the development problems of high-temperature and high-pressure reservoirs, the application optimization strategies of carbon dioxide flooding enhanced oil recovery technology are systematically discussed. Through the analysis of the characteristics of high-temperature and high-pressure reservoirs and the mechanism of carbon dioxide flooding, combined with numerical simulation and field practice cases, the influence of key parameters such as gas injection pressure, injection rate, injection volume, and CO₂ concentration on the oil displacement effect was deeply studied. This paper proposes a comprehensive application scheme that optimizes injection-production well pattern, innovates wellbore insulation technology and combines other stimulation technologies to provide theoretical basis and practical guidance for the efficient development of high-temperature and high-pressure reservoirs.

Influence of salt-biosurfactant-biosynthesized silica nanoparticle on oil-water interfacial dynamics

2025-06-21

Anurag Mishra , Pankaj Tiwari , Lalit M. Pandey | Fuel

Fractal Analysis of Evaporation-Imbibition in Porous Media Including Gravity

2025-06-20

Yuzeng Duan , Tiantian Xie , Mingqing Zou +3 more | Fractals

Hydrogen-Bond-Modulated Flowable Weak Gel for EOR in ultra-high temperature and ultra-high salinity fracture-cavity ordinary heavy oil reservoirs

2025-06-19

Minghao Xue , Lifeng Chen , Haiqun Chen +5 more | Colloids and Surfaces A Physicochemical and Engineering Aspects

Development of fluids containing silicon dioxide extracted from Agro-Industry waste and tamarind gum for wettability alteration of carbonate rocks

2025-06-18

Maria Ester Vaz , Priscila F. Oliveira , CAROLINA R A CRUZ +4 more | Fuel

Chemical incompatibility between formation and injection water: implications for oil recovery in porous media

2025-06-18

Jiangtao Wang , Xiaolong Wan , Xuejun Ren +3 more | Frontiers in Chemistry

Low-salinity water flooding is widely recognized as an effective enhanced oil recovery (EOR) method, primarily by altering wettability and reducing interfacial tension. However, chemical incompatibility between injected water and formation … Low-salinity water flooding is widely recognized as an effective enhanced oil recovery (EOR) method, primarily by altering wettability and reducing interfacial tension. However, chemical incompatibility between injected water and formation water may induce scale deposition, leading to pore blockage and injectivity impairment, thereby posing significant challenges to EOR efficiency. A better understanding of the interplay between chemical incompatibility and pore-scale oil-water interface dynamics is crucial for optimizing waterflooding performance, particularly in low-permeability reservoirs. This study integrates ion characterization, colloidal analysis, solubility product calculations, and microfluidic visualization to systematically evaluate the compatibility of formation and injected waters, while directly observing pore-scale fluid displacement processes. Results reveal that ionic composition analysis reveals significant incompatibility between the sulfate-rich injection water and calcium/barium-containing formation water, creating conditions favorable for mineral scaling. Subsequent examination of scaling dynamics demonstrates that incompatible fluid mixing initiates nanoparticle formation, which progresses through two distinct growth pathways: coalescence-driven crystal enlargement and aggregation-dominated cluster formation, ultimately leading to pore-throat obstruction. Microfluidic visualization shows residual oil persists primarily as interfacial films and pore-center clusters after initial waterflooding, with their spatial arrangement governed by salinity-dependent wettability alteration and capillary forces. The introduction of incompatible water further exacerbates fluid trapping through capillary valve effects—a capillary-driven resistance occurring when interfacial forces oppose fluid advancement at pore-throat junctions—creating stagnant zones that promote particle accumulation. Pressure monitoring during flooding experiments reveals characteristic response patterns: an initial pressure peak during waterflooding, followed by secondary pressure elevation due to scale deposition, and subsequent partial pressure reduction through surfactant-mediated interfacial tension reduction and wettability modification. A self-reinforcing cycle emerges, coupling ion incompatibility, capillary trapping, and precipitate growth, encapsulated in a colloid-capillary coupling framework. To disrupt this cycle, a synergistic chemical strategy combining surfactants and scale inhibitors is proposed, simultaneously enabling interface modification and nucleation suppression to enhance sweep efficiency. This integrated approach provides a mechanistic foundation for optimizing waterflooding in chemically complex reservoirs, achieving a balanced synergy between interfacial control and scale mitigation.

Remaining Oil Distribution Characteristics and Potential Tapping Strategies for Integral Reservoirs at Different Waterflooding Stages

2025-06-18

Hongmin Yu , Youqi Wang , Qinglin Shu +7 more | ACS Omega

Molecular dynamics simulation and field validation of biosurfactant for low-temperature water-in-heavy oil demulsification

2025-06-18

Chuxiao Hu , Xuan Ou , Xiongjie Zheng +7 more | Fuel

Synergistic application of air-foam flooding and corrosion inhibition technologies: mechanisms and performance evaluation in enhanced oil recovery systems

2025-06-17

D. S. Xue , Yingxue Bai , Dongliang Zhao +5 more | Tenside Surfactants Detergents

Abstract The contemporary foam oil drive technology is impeded by two critical issues: the instability of the foaming agent and the corrosive impact of airborne O 2 on injection and … Abstract The contemporary foam oil drive technology is impeded by two critical issues: the instability of the foaming agent and the corrosive impact of airborne O 2 on injection and production pipelines. These challenges significantly impact the safe and efficient operation of oil fields. Given the unique molecular structure of surfactants, this study proposes an innovative integrated formulation that combines air-foam oil displacement with a corrosion inhibitor to effectively address these limitations. The results show that the integrated air-foam oil displacer-corrosion inhibitor all-in-one formulation SSTN (0.8 % BS-12 + 0.6 % AES + 0.07 % CTAB + 500 mg L −1 N 2 H 4 –H 2 O) exhibits exceptional foaming efficiency and salt resistance. When interacting with simulated condensate, the SSTN foam shows remarkable stability, with the ability to tolerate condensate concentrations in excess of 10 %. In addition, the SSTN solution exhibits superior corrosion inhibition efficacy, as confirmed by both static pendant drop and electrochemical methods, confirming the multi-functionality of this integrated agent. At lower concentrations, SSTN can effectively reduce surface tension, achieving an oil displacement efficiency of 25.37 % in core simulation experiments. The development of this integrated air-foam oil displacement-corrosion inhibitor provides a valuable reference for related fields and has significant potential for application in enhancing oil recovery in oilfields.

Investigation on enhanced oil recovery by chemical compound flooding after thermal recovery in high permeability heavy oil reservoirs

2025-06-17

Lei Tao , Xikang Zheng , Hai Zhu +7 more | Petroleum Science and Technology

Pore-scale mechanics of thermal viscous fingering in miscible reactive flow displacement through porous media

2025-06-17

Weiyu Zhang | Physica Scripta

Abstract This study investigates the thermal miscible displacement problem with heterogeneous reactions at the pore scale, focusing on the effects of Damk¨ohler number (Da) and Lewis number (Le) on the … Abstract This study investigates the thermal miscible displacement problem with heterogeneous reactions at the pore scale, focusing on the effects of Damk¨ohler number (Da) and Lewis number (Le) on the dynamics of thermal viscous fingering, solid structure changes, and displacement efficiency. A critical Damk¨ohler number (Da ≈ 0.2) is identified, marking the transition between purely diffusiondominated and reaction–diffusion coupled regimes. When Da < 0.2, dissolution reactions have limited impact, and final displacement efficiency (De) is primarily governed by Le; increasing Le enhances thermal diffusion, smooths the temperature front, and improves De. However, when Da > 0.2, dissolution reactions significantly alter pore structures, causing a shift from multi-fingered to wormhole-type patterns as Le rises. This transition leads to an initial decline and then recovery of De within the critical Le range of approximately 2.0–4.5. Furthermore, the results reveal a notable deviation from previous REV-scale models without dissolution reactions: at Le < 2.0, reduced thermal dissipation intensifies front instability and channel broadening, enhancing De, whereas at Le > 4.5, strong thermal diffusion dominates, promoting interface smoothing and improved channel connectivity to optimize De. These findings provide new insights for the design and optimization of carbon sequestration in practical applications.

Temporal and spatial temperature distributions and heavy oil production performances in hot-water flooding processes at different water temperatures and injection rates

2025-06-17

Jiangyuan Yao , Wei Zou , Yongan Gu | Case Studies in Thermal Engineering

On the influence of macro-scale stress variations on the dynamic dewatering of water-saturated polymer fibre networks

2025-06-16

Patrick Wegele , Daniel Söderberg | Nordic Pulp & Paper Research Journal

Abstract Efficient mechanical dewatering in paper manufacturing is essential for reducing energy consumption and enhancing operational efficiency. Practical observations indicate that press felt and roll cover structures significantly influence dewatering … Abstract Efficient mechanical dewatering in paper manufacturing is essential for reducing energy consumption and enhancing operational efficiency. Practical observations indicate that press felt and roll cover structures significantly influence dewatering performance. While previous studies have focused on micro-scale stress variations at the paper web-press felt interface, this study extends the analysis to the press felt-roll cover interface. Using a custom dynamic compression setup, we investigate how different groove patterns impact press felt dewatering. The results show that macro-scale stress variations play a crucial role, with controlled mechanical inhomogeneities enhancing felt permeability. Through multivariate regression analysis, an optimized groove pattern is identified that improves dewatering by approximately 7 % under highly dynamic pressing conditions. These findings offer valuable insights into optimizing press felt and roll cover interactions, providing a methodology to enhance nip dewatering efficiency. The study highlights the need to tailor groove patterns to specific press felts to ensure optimal water flow under saturated conditions. This research contributes to improving paper machine performance by maximizing water removal while reducing energy consumption, supporting both economic and environmental sustainability in the industry.

Comprehensive Experimental Study of Steam Flooding for Offshore Heavy Oil Recovery After Water Flooding

2025-06-15

Wei Zhang , Yigang Liu , Jian Zou +4 more | Energies

The objective of this study is to investigate the feasibility of steam flooding (SF) as an alternative method for offshore heavy oil reservoirs after water flooding (WF). A series of … The objective of this study is to investigate the feasibility of steam flooding (SF) as an alternative method for offshore heavy oil reservoirs after water flooding (WF). A series of experiments was performed by using specially designed one-dimensional (1-D) and three-dimensional (3-D) experimental systems to prove the feasibility of SF and to study the effects of the timing of SF, the steam injection rate, and the addition of chemical agents (the nitrogen foams and displacing agents) on the performance of SF after WF. The results showed that, for offshore heavy oil reservoirs after WF processes, the SF process is a viable enhanced oil recovery method, which should start as early as possible if the economic conditions permit. It is extremely important to choose an appropriate steam injection rate for SF after the WF process. Compared with the pure SF process, the final oil recovery of the SF process with the addition of the nitrogen foam or the displacing agent increased by 12.83% and 7.58% in the 1-D experiments, respectively. The nitrogen foam and displacing agent have synergistic effects on the performance of the SF after WF processes. The final oil recovery of the SF process with the addition of the two chemical agents at the steam injection rate of 10 mL/min was 37.64%, which was 5.47% higher than that of the pure SF process in the 3-D experiments.

A novel green nanocomposite suppresses asphaltene precipitation: Multiscale analysis from AFM to core flooding in carbonates

2025-06-13

Yaser Ahmadi , David A. Wood | Research Square (Research Square)

<title>Abstract</title> Asphaltene deposition in oil and gas reservoirs presents numerous operational challenges. Recent studies have explored the application of various nanoparticle-based solutions to mitigate asphaltene precipitation. In this study, a … <title>Abstract</title> Asphaltene deposition in oil and gas reservoirs presents numerous operational challenges. Recent studies have explored the application of various nanoparticle-based solutions to mitigate asphaltene precipitation. In this study, a novel ZnO/SiO2/xanthan/eucalyptus nanocomposite of solid materials (NCs) was investigated for asphaltene inhibition in carbonate porous media. The asphaltene adsorption potential of NCs was evaluated through a series of experiments, including ultraviolet-visible (UV-Vis) spectroscopy, CO₂/oil interfacial tension measurements, and atomic force microscopy (AFM), under realistic carbonate-reservoir conditions following material characterization. Given its superior asphaltene adsorption performance in preliminary tests, NCs was selected for subsequent natural depletion studies to monitor asphaltene deposition in porous media. Adsorption isotherm analysis revealed that the Langmuir model provided a better fit than the Freundlich model for NCs, indicating monolayer adsorption behavior. Furthermore, interfacial tension assessments demonstrated that NCs exhibited enhanced asphaltene adsorption capacity, particularly at pressures of 3700, 3500, and 3300 psi conditions, under which natural depletion experiments were conducted. AFM and adsorption tests yielded consistent surface roughness trends. Upon treatment with NCs, the average roughness (<italic>Rₐ</italic>), peak-to-valley roughness (<italic>Rₜ</italic>), and root-mean-square roughness (<italic>R</italic><italic>q</italic>) of carbonate substrates decreased significantly. Specifically, <italic>Rₐ</italic> declined from 56.70 ± 1.42 nm to 11.42 ± 0.25 nm, while <italic>Rₜ</italic> decreased from 335.71 ± 2.64 nm to 13.23 ± 1.74 nm when subjected to NCs exposure. Similarly, <italic>R</italic><italic>q</italic> was reduced from 67.21 ± 1.39 nm to 12.52 ± 0.56 when subjected to NCs exposure. The application of NCs was found to mitigate permeability and porosity reduction in carbonate formations while effectively minimizing asphaltene deposition.

Experimental evaluation and development demonstration of nitrogen flooding in fractured block oil reservoirs – taking the case of a well area in Tankou Oilfield

2025-06-13

Yuan Yang | Petroleum Science and Technology

Comprehensive Study on Viscosity-Increasing and Oil Displacement Characteristics of Functional Polymer

2025-06-12

Jingang He , Xian'gao Jin , Xiaoying Liu +7 more | Processes

Polymer flooding is one of the critical methods for enhancing oil recovery (EOR) in domestic and international oilfields. Since the large-scale implementation of industrial polymer flooding in Daqing Oilfield in … Polymer flooding is one of the critical methods for enhancing oil recovery (EOR) in domestic and international oilfields. Since the large-scale implementation of industrial polymer flooding in Daqing Oilfield in 1996, the overall recovery rate has increased by over 10%. With the advancement of chemical flooding technologies, conventional polymer flooding can no longer meet the practical demands of oilfield development. This study focuses on functional polymers, such as salt-resistant polymers and polymeric surfactants, tailored for Class II and III reservoirs in Daqing Oilfield. A series of experiments, including emulsification experiments, hydrodynamic characteristic size-reservoir compatibility comparison experiments, polymer retention experiments in porous media, and core flooding experiments, were conducted to investigate the differences between functional polymers and conventional polymers in terms of intrinsic properties and application performance. Comparative analyses of molecular chemical structures and micro-aggregation morphologies between functional polymers (branched polymers and polymeric surfactants) and conventional polymers revealed structural composition disparities and distinct viscosity-enhancing properties. From the perspective of aqueous solution viscosity enhancement mechanisms, functional polymers exhibit a three-stage viscosity-enhancing mechanism: bulk viscosity, associative viscosity, and emulsion-induced viscosity enhancement. The hydrodynamic characteristic sizes of polymers were analyzed to evaluate their compatibility with reservoir pore structures, and the seepage resistance mechanisms of both polymeric surfactants and salt-resistant polymers were identified. Core flooding experiments conclusively demonstrated the superior practical performance of functional polymers over conventional polymers. The application of functional polymers in polymer flooding can effectively enhance oil recovery.

Preparation of Cationic Fluoropolymer Emulsions and Their Applications as Novel Wettability‐Reversing Agents for Enhanced Oil Recovery

2025-06-12

Shen Hu , Lei Wang , Hongmei Du +6 more | Journal of Applied Polymer Science

ABSTRACT During oil exploitation, severe water lock damage hinders the efficiency of resource extraction. Therefore, developing wettability‐reversing agents to improve reservoir wettability is important. In this study, new cationic fluoroacrylate … ABSTRACT During oil exploitation, severe water lock damage hinders the efficiency of resource extraction. Therefore, developing wettability‐reversing agents to improve reservoir wettability is important. In this study, new cationic fluoroacrylate emulsions (FED emulsions) were synthesized by incorporating a short‐chain fluoro‐monomer and a cationic monomer. Findings revealed that one of the FED emulsions exhibited excellent water solubility and adsorption properties. After treatment with 2.0 wt% FED emulsion, the water contact angle on the core surface increased from 84.3° to 130.2°, the kerosene contact angle increased from 1° to 70.3°, the surface free energy was reduced by 87.54%, and the discharge rate increased by 44.02%. The capillary self‐priming height was reduced by 30.56%. Core displacement experiments revealed that the FED emulsion reduced injection pressure while enhancing oil recovery, achieving a 14.91% improvement in recovery efficiency. The compatibility of the FED emulsion with polymer fracturing fluid was evaluated, and the results confirmed good compatibility between the two. Our findings establish the FED emulsion as an effective wettability‐reversing agent, capable of transforming reservoirs from hydrophilic and oleophilic to hydrophobic and oleophobic.

Experimental study on steam channeling and profile control in thin loose sandstone heavy oil reservoir

2025-06-12

Jiajing Chang , Zhaojie Song , Yongqiang Tang +2 more | Journal of Dispersion Science and Technology

A molecular perspective on the microscopic mechanisms of CO2 injection and water films in fluid transport and enhanced oil recovery

2025-06-11

Junyao Bao , Jiapei Du , Shiyuan Zhan +2 more | ADVANCES IN GEO-ENERGY RESEARCH

Evaluation of nanoemulsion properties in tight sandstone reservoir

2025-06-11

Yuan Li , Pengcheng Fu , L L Zhang +7 more | Journal of Molecular Liquids