The Flow of Foam Through Short Porous Media And Apparent Viscosity Measurements

1966 ◽  
Vol 6 (01) ◽  
pp. 17-25 ◽  
Author(s):  
S.S. Marsden ◽  
Suhail A. Khan
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Shear Rate ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Apparent Viscosity ◽  
Viscosity Ratio ◽  
Surfactant Solution ◽  
Liquid Saturation ◽  
Liquid Displacement

Abstract Externally generated foam was injected continuously into short porous media. Both flow rate and pressure drop were measured. Liquid saturation was determined by electrical conductivity. Foam quality G, expressed as the ratio of gas volume to total volume, was varied from 0.70 to 0.96. As measured with a modified Fann VG Meter, apparent viscosity of this foam µa decreases with increasing shear rate but usually falls within the range of 50 to 500 cp. At a given shear rate, µa increases almost linearly with G. When measured with a Bendix Ultraviscoson, kinematic µa is independent of r but absolute µa increases with r from about 3 to 8 cp. The effective permeability-apparent viscosity ratio ke/µa decreases almost linearly with G for porous media of high permeability, but the rate of decrease becomes less for tighter ones. The relative permeability-apparent viscosity ratio kr/µa vs G data does not fall on a single line. The kr/µa ratio increases with liquid saturation in the porous medium and with surfactant concentration. Estimates of µa for foam in porous media vary from 30 to 100 cp. INTRODUCTION Although research on the development of a foam-drive, oil recovery process has been going on for almost a decade, most of the significant publications have appeared within the last several years. This illustrates well the rate at which interest in this process is accelerating. Bond and Holbrook1 were the first to describe the use of foam to improve oil recovery in their patent of 1958. They proposed that an aqueous foaming agent slug be injected into the formation and that this be followed by gas to produce a foam in situ. Fried2 studied the injection of foam into porous media which has already been subjected to conventional gas or water drives and found that gas could be used to drive a foam bank which would, in turn, displace additional oil in the form of an oil bank. He attributed the increased oil recovery to the high effective viscosity of foam flowing in porous media. His microscopic observations showed the importance of foam generation and regeneration within the porous medium. By injecting both air and aqueous surfactant solution, Bernard3 generated foams within the porous medium in which oil displacement was being studied. In a separate empirical test, he also measured the dynamic foaming characteristics of the same surfactants in water and/or oil. With some exceptions and for the seven surfactants studied, there seems to be a qualitative relationship between the efficiency of liquid displacement and the dynamic foaming test used. This relationship was not consistent enough to eliminate the necessity of actual foam flood tests in porous media for surfactant selection. In a study basic to gas storage in aquifers, Bennett4 described the displacement of brine by foam in consolidated porous media. Among other things, he stated that the ability of a surfactant solution to foam is more important than the stability of its foam. The presence of a foam bank between the displacing air and the displaced brine improved both breakthrough and ultimate recovery. In a continuation of this work Kolb5 attributed the great reduction in surfactant solution production rate as displacement by air progressed to a decrease in relative permeability to gas. These several effects reported by both Bennett and Kolb can all be attributed to the high apparent viscosity of foam which was obviously flowing in the porous media.

Interfacial Effects in Immiscible Liquid-Liquid Displacement in Porous Media

1966 ◽  
Vol 6 (03) ◽  
pp. 247-253 ◽  
Author(s):  
Necmettin Mungan
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Viscosity Ratio ◽  
Active Material ◽  
Immiscible Liquid ◽  
Low Surface Energy ◽  
Surface Active ◽  
Surface Active Material ◽  
Liquid Displacement

Abstract A study was made of the effects of wettability and interfacial tension the immiscible displacement of a liquid by another liquid for porous media. The influence of viscosity ratio was also investigated. Porous media used were polytetrafluoroethylene (TFE) cores prepared by compressing TFE powder under different pressures. It is shown that displacement of a wetting by a nonwetting liquid is always less efficient than the displacement of a nonwetting by a wetting fluid, all other things being equal. In the former case, the recovery efficiency can be increased substantially by either reducing the interfacial tension or increasing the viscosity of the displacing fluid. A qualitative discussion is given on the implications of this work to the recovery of crude oil by waterflooding. Introduction The high cost of oil exploration and new recovery schemes makes it imperative that waterflooding be conducted under conditions favoring most efficient oil recovery. To improve oil recovery by waterflooding, it is essential that the role played by interfacial forces in the entrapment of residual oil be studied and understood. Interfacial phenomena in natural rock, connate water and crude oil systems are very complicated because of the complexity of the natural liquids found in petroleum reservoirs, because of our inability to adequately describe the geometrical structure of the porous media and because of a lack of understanding of physical and chemical interactions between the liquids and surface of the pores. The problem becomes further complicated when one tries to elucidate the role of interfacial phenomena in fluid flow. Numerous studies of the displacement of oil by water under different interfacial tension or wettability conditions have been made. These studies have been performed in silica, alundum or sandstone systems using water and paraffin oil and also some surface active material to control the interfacial tension or and the contact angle. Unfortunately, the high energies of various interfaces involved favor adsorption and orientation of the surface active material at the intrafaces. Also the surface active material concentration at the interfaces exceeds that in the bulk of the liquid phases. Such surface excess may cause the surfactant distribution, the contact angle and the interfacial tension to differ from their measured static equilibrium values and makes interpretation of the displacement experiments difficult. Furthermore, as changes in also lead to changes in cos, the role played individually by one of these parameters in the displacement becomes obscured by the effect of the other. To circumvent these difficulties, a low surface energy solid and true solutions or pure liquids should be used. Use of a low surface energy solid minimizes adsorption and orientation effects at the solid-liquid interfaces. By controlling and cos through use of selected pairs of pure liquids or true solutions rather than by surfactants, the adsorption effects at liquid-liquid interfaces are eliminated. In the present study TFE cores were used as me porous media. Liquids used were water sucrose solutions, paraffin oils and benzyl, n-butyl and isobutyl alcohols. The interfacial tension was varied from 40 to 1.1 dynes/cm by suitably choosing the liquid pair. A surface above material was added to the water-oil system only in the case where interfacial tension of 0.5 dynes/ cm was desired. No precise changes of cos were attempted. However, either the displaced or the displacing liquid could be made the one which preferentially wets the TFE surface. Using sucrose solutions and blends of paraffin oils proved to be a convenient way of changing the viscosity ratio between the displaced and displacing liquids. The present investigation examines the effect of interfacial tension, wettability and viscosity ratio on the immiscible liquid-liquid displacement from porous media. SPEJ P. 217ˆ

Pseudo-Plastic Behavior of a Film Foam Flow with Carbon Dioxide as the Internal Gas Phase

2011 ◽  
Vol 221 ◽  
pp. 15-20 ◽  
Author(s):  
Dong Xing Du ◽  
Ying Ge Li ◽  
Shi Jiao Sun
Keyword(s):  
Porous Media ◽  
Shear Rate ◽  
Gas Phase ◽  
Oil Recovery ◽  
Apparent Viscosity ◽  
Flow Behavior ◽  
Plastic Behavior ◽  
Straight Tube ◽  
Foam Flow ◽  
Co2 Foam

There are many attractive features for using CO2 foam injection in Enhanced Oil Recovery (EOR) processes. For understanding CO2 foam rheology in porous media, an experimental study is reported in this paper concerning CO2 film foam flow characteristics in a vertical straight tube. Foam is treated as non-Newtonian fluid and its pseudo-plastic behavior is investigated based on power law constitutive model. It is observed the CO2 film foam flow shows clear shear-thinning behavior, with flow consistency coefficient of K=0.15 and flow behavior index of n=0.48. The apparent viscosity of flowing CO2 film foam is under the shear rate of 50s-1 and under the shear rate of 1000s-1, which are 19 and 3 times higher than the single phase water. It is also found CO2 foam has lower apparent viscosity than the foam with air as the internal gas phase, which is in consistence with experimental observations for lower CO2 foam flow resistance in porous media.

Capillary Impregnation of Viscous Fluids in a Multi-Layered Porous Medium

2019 ◽  
Author(s):  
Shabina Ashraf ◽  
Jyoti Phirani
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Viscous Fluids ◽  
Spontaneous Imbibition ◽  
Lab On Chip ◽  
Capillary Impregnation ◽  
Relative Placement ◽  
Homogeneous Porous Medium ◽  
Wetting Fluid

Abstract Capillary impregnation of viscous fluids in porous media is useful in diagnostics, design of lab-on-chip devices and enhanced oil recovery. The impregnation of a wetting fluid in a homogeneous porous medium follows Washburn’s diffusive law. The diffusive dynamics predicts that, with the increase in permeability, the rate of spontaneous imbibition of a wetting fluid also increases. As most of the naturally occurring porous media are composed of hydrodynamically interacting layers having different properties, the impregnation in a heterogeneous porous medium is significantly different from a homogeneous porous medium. A Washburn like model has been developed in the past to predict the imbibition behavior in the layers for a hydrodynamically interacting three layered porous medium filled with a non-viscous resident phase. It was observed that the relative placement of the layers impacts the imbibition phenomena significantly. In this work, we develop a quasi one-dimensional lubrication approximation to predict the imbibition dynamics in a hydrodynamically interacting multi-layered porous medium. The generalized model shows that the arrangement of layers strongly affects the saturation of wetting phase in the porous medium, which is crucial for oil recovery and in microfluidic applications.

Visualization of a Surfactant Flood of an Oil-Saturated Porous Medium

1984 ◽  
Vol 24 (03) ◽  
pp. 325-327 ◽  
Author(s):  
L. Paterson ◽  
V. Hornof ◽  
G. Neale
Keyword(s):  
Porous Medium ◽  
Oil Recovery ◽  
Capillary Number ◽  
Saturated Porous Medium ◽  
Surfactant Solution ◽  
Viscous Fingering ◽  
Water Flooding ◽  
Alkyl Aryl Sulfonate ◽  
Oil Viscosity ◽  
Paraffin Oil

Abstract This paper discusses the viscous fingering that occurs when water or a surfactant solution displaces oil in a porous medium. Such floods were visualized in an porous medium. Such floods were visualized in an oil-wet porous medium composed of fused plastic particles. The flow structure changed significantly within the range of capillary numbers between 10 -4 and 10 -3 . The addition of surfactant resulted in narrower fingers, which developed in a more dispersive fashion. Introduction In describing fluid/fluid displacements in porous media, a useful dimensionless quantity is the capillary number, (1) which corresponds to the ratio of viscous forces to capillary forces. Here, v is the specific fluid discharge or Darcy velocity, it is viscosity, and o is interfacial tension (IFT). It has been shown that the recovery of oil from an underground reservoir increases significantly if the capillary number can be increased beyond the range of 1 × 10 -4 to 2 × 10 -3 during water flooding (see Larson et al. 1 ). To this end, surfactants are used extensively in tertiary oil recovery operations with the objective of reducing IFT and consequently mobilizing the oil ganglia which otherwise would remain trapped. This paper is concerned with the viscous fingering that occurs when water displaces oil in a porous medium, and we present a brief consideration on the effects that surfactants have on fingering. Noting that Peters and Flock have visualized fingering within the range of capillary numbers between 1.6 × 10 -6 and 7.2 × 10 -4, we present here visualizations at capillary numbers of 7.7 × 10 5 and 1.0 × 10 -3. Both our visualizations and the experiments of Peters and Flock involve large viscosity ratios so that only the viscosity of the more viscous fluid is considered when determining the capillary number. In particular, it is observed that as the capillary number increases, ganglia or blobs of displacing fluid are created at the displacement front in correspondence with the capillary numbers at which trapped ganglia are mobilized. This creation of ganglia at capillary numbers above 10 -3 was noted briefly in a previous paper 3 in which heptane displacing glycerine previous paper 3 in which heptane displacing glycerine was described. A secondary objective of this work was to test the Chuoke et al. theory for predicting the wavelength of fingers, wavelength being the peak-to-peak distance between adjacent well-developed fingers. Experimental Procedure The apparatus for these studies was described in Ref. 3. Basically, it consists of a slab of consolidated plastic particles 1.34 × 0.79 × 0.0 1 8 ft [0.44 × 0.26 × 0.006 m] with particles 1.34 × 0.79 × 0.0 1 8 ft [0.44 × 0.26 × 0.006 m] with a porosity of 0.43 and a permeability of 7, 100 darcies. This high permeability, when compared with that of reservoir rocks, should not be important for this study since capillary numbers and residual saturations are independent of pore size. Water (viscosity 1 cp [1 mPa s]) was used to displace paraffin oil (viscosity 68 cp 168 mPa s] at 77F [25C]). The water was dyed with methylene blue (which acts as a mild surfactant). Without the dye, the oil/water IFT was 42 dyne/cm [42 mN/m]. The addition of dye lowered this value to 36 dyne/cm [36 mN/m] for the concentration of dye used. For the surfactant flood, a 1 % sodium alkyl aryl sulfonate solution was used, giving a surfactant-solution/paraffin-oil IFT of 3.0 dyne/cm [3.0 mN/m]. Water Displacing Oil To compare our experiments with previous investigations of fingering, the displacement of paraffin oil by water at an average specific fluid discharge of 1.34 × 10–4 ft/sec [4.1 × 10 -5 m/s], corresponding to a capillary number of 7.7 × 10 -5, was studied (Fig. 1). Chuoke et al .4 and later Peters and Flock 2 have presented a formula for predicting the wavelength of presented a formula for predicting the wavelength of finger, lambda m : (2) where k is permeability, C is a dimensionless parameter which Peters and Flock call the wettability number and suggest would have the value 25 for an oil-wet porous medium, and mu o and mu ware viscosities of the displaced oil and displacing water, respectively. It was observed that the plastic particles of the porous medium considered here were oil wet because of adsorption of oil. SPEJ P. 325

An Imbibition Model - Its Application to Flow Behavior and the Prediction of Oil Recovery

1961 ◽  
Vol 1 (02) ◽  
pp. 61-70 ◽  
Author(s):  
J. Naar ◽  
J.H. Henderson
Keyword(s):  
Porous Medium ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Pore Geometry ◽  
Mathematical Treatment ◽  
Complete Wetting ◽  
Permeability Characteristics ◽  
Relative Permeability Curves ◽  
Wetting Fluid

Introduction The displacement of a wetting fluid from a porous medium by a non-wetting fluid (drainage) is now reasonably well understood. A complete explanation has yet to be found for the analogous case of a wetting fluid being spontaneously imbibed and the non-wetting phase displaced (imbibition). During the displacement of oil or gas by water in a water-wet sand, the porous medium ordinarily imbibes water. The amount of oil recovered, the cost of recovery and the production history seem then to be controlled mainly by pore geometry. The influence of pore geometry is reflected in drainage and imbibition capillary-pressure curves and relative permeability curves. Relative permeability curves for a particular consolidated sand show that at any given saturation the permeability to oil during imbibition is smaller than during drainage. Low imbibition permeabilities suggest that the non-wetting phase, oil or gas, is gradually trapped by the advancing water. This paper describes a mathematical image (model) of consolidated porous rock based on the concept of the trapping of the non-wetting phase during the imbibition process. The following items have been derived from the model.A direct relation between the relative permeability characteristics during imbibition and those observed during drainage.A theoretical limit for the fractional amount of oil or gas recoverable by imbibition.An expression for the resistivity index which can be used in connection with the formula for wetting-phase relative permeability to check the consistency of the model.The limits of flow performance for a given rock dictated by complete wetting by either oil or water.The factors controlling oil recovery by imbibition in the presence of free gas. The complexity of a porous medium is such that drastic simplifications must be introduced to obtain a model amenable to mathematical treatment. Many parameters have been introduced by others in "progressing" from the parallel-capillary model to the randomly interconnected capillary models independently proposed by Wyllie and Gardner and Marshall. To these a further complication must be added since an imbibition model must trap part of the non-wetting phase during imbibition of the wetting phase. Like so many of the previously introduced complications, this fluid-block was introduced to make the model performance fit the observed imbibition flow behavior.

Optimal Injection Strategies for the Propagation of Surfactant Mixtures Through Porous Media

1984 ◽  
Vol 24 (05) ◽  
pp. 545-554 ◽  
Author(s):  
Jeffrey H. Harwell ◽  
Robert S. Schechter ◽  
William H. Wade
Keyword(s):  
Molecular Weight ◽  
Porous Media ◽  
Oil Recovery ◽  
Chromatographic Separation ◽  
Surfactant Solution ◽  
Commercial Application ◽  
Recovery Efficiency ◽  
Surfactant Mixtures ◽  
Optimal Injection ◽  
Injection Strategies

Abstract The chromatographic movement of surfactant mixtures through porous media is examined to determine possible injection strategies for minimizing the amount of surfactant required in a tertiary oil recovery chemical flood. The model used does not consider the presence of oil but does account for mixed micelle formation. Expressions are derived that represent the surfactant required to expose an entire reservoir to an "effective oil recovery mixture." This effective mixture may be either one whose overall composition is within prescribed limits of the composition of the injected surfactant solution or it may be a mixture whose overall composition varies but which contains micelles of fixed composition. Mixtures considered contain cosolvents and one, two, or three surfactant components. Initial calculations neglect dispersion, but numerical calculations including dispersion leave the conclusion unchanged; within the limitations of the model, there are optimal strategies for the propagation of surfactant mixtures through porous media. The optimal injection strategy varies, depending on the nature of the surfactant solution injected into the porous medium. Conditions for and the location of the optimum are discussed. Conclusions based on observations about these systems then are extended to cover the injection of surfactant mixtures currently available commercially. Introduction Commercial application of surfactants for EOR now appears feasible. The principle at work in such processes is the lowering of interfacial tension (IFT) between the continuous flowing water and trapped residual oil droplets to allow the oil to be mobilized. Mixtures that effectively lower oil/water IFT are often blends of various surfactant types, isomers of the same surfactant, and/or cosurfactants in an electrolyte solution. The oil recovery efficiency of the injected mixture generally is quite sensitive to changes in mixture composition. Change of composition after injection into the reservoir may occur by one or a combination of mechanisms. For example, the mixture components may partition selectively into the various phases present in the reservoir. The mechanism considered here is the chromatographic separation of the mixture into its components due to preferential adsorption of various components onto reservoir minerals-"the chromatographic problem." The recent reports of the Bell Creek Unit A micellar/polymer pilot showed 20% of the injected surfactant produced before any oil bank with negligible concomitant incremental tertiary oil production. Significantly, the surfactants produced were the lower-molecular-weight species. Though alternative mechanisms for this separation yet may be established, the hypothesis of chromatographic separation of the components in the mobile aqueous phase seems adequate. Not only did this produced surfactant not result in enhanced recovery, but since the injected solution was designed to give ultralow IFT's with the low-molecular-weight components in place, it seems likely that the oil recovery efficiency of the remaining surfactant also may have been impaired. These results emphasize the importance of understanding the mechanisms of surfactant chromatographic movement. One means of combatting the chromatographic problem is to reduce the local adsorption of the mixture components-that is, modify the adsorption isotherms of the constituents. This may be done either by changing the reservoir minerals (e.g., by a caustic flood) or by modifying the structure of the surfactant molecules. A complementary approach is to examine the dynamics of the chromatographic movement of surfactant mixtures to identify injection strategies, if they exist, that minimize the total surfactant requirement. It is this question that is considered here. The analysis considers an oil-free linear system and neglects many of the complex features that are encountered in an actual chemical flood. There are several reasons for ignoring these complicating factors. The coherence solutions apply to the systems considered here; whereas the only solutions that include the presence of oil employ numerical computations. An analytical solution is desirable; however, there is an additional more compelling argument that has been used to justify neglecting the presence of oil. The chromatographic movement of a surfactant/ cosurfactant mixture through an oil-free core should demonstrate the qualitative features of the actual oil recovery process. While multiple flowing phases do arise in an actual flood, the released oil forms a bank ahead of the surfactant slug. SPEJ P. 545^

Numerical Calculation of Flow Characteristics of Enhanced Foam System in Porous Medium

2016 ◽  
Vol 9 (1) ◽  
pp. 29-36
Author(s):  
Chengli Zhang ◽  
Guodong Qu ◽  
Guoqiang Cui ◽  
Mingxing Bai
Keyword(s):  
Porous Media ◽  
Numerical Calculation ◽  
Unsteady Flow ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Surfactant Solution ◽  
Average Density ◽  
Chemical Flooding ◽  
Flow Front ◽  
Foam Flooding

Enhanced foam flooding is a chemical flooding technology, which is applied to improve the recovery efficiency of oil and gas. The oil displacement agent of enhanced foam flooding is a foam that the polymer and surfactant solution as liquid. In this paper, three-dimensional mathematical model of unsteady flow is established about enhanced foam system in the porous media, and the numerical calculation method is given to study the enhanced foam flooding. The results show that: the unsteady flow of enhanced foam system in porous media exists flow front, the flow foam average density of flow front reach the peak; enhanced foam flooding can form the oil bank in the displacement front and the oil saturation of the oil bank reaches about 0.55, the oil bank can produce effective drive to remain oil and then improve oil recovery.

Technology Focus: EOR Modeling (January 2021)

2021 ◽  
Vol 73 (01) ◽  
pp. 43-43
Author(s):  
Subodh Gupta
Keyword(s):  
Machine Learning ◽  
Porous Media ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Data Science ◽  
Reservoir Characterization ◽  
Flow In Porous Media ◽  
Reservoir Modeling ◽  
Permeability Estimation ◽  
Variable Chemical

The enhanced-oil-recovery (EOR) literature produced in the past several months was dominated by reservoir modeling and characterization; flood enhancements; machine learning; and, more notably, relative permeability estimation. This last one needs to be under-stood further. Relative permeability characterizes flow in porous media, the understanding and manipulating of which is key to the success of EOR. Our fascination with the topic during the last 75 years, therefore, is understandable. Starting with a seminal paper from W.R. Purcell in 1949, we have more than 12,000 articles in the SPE collection alone on relative permeability estimation, of which more than 400 were published in the last year. Mechanics of motion is also important to mankind, but we do not have literature piling up on Newton’s laws of motion. Is it that we haven’t understood flow in porous media yet, or is it because the subject matter is so complex? The truth, perhaps, lies somewhere in between. Flow in pores that are randomly sized, randomly connected, and have variable chemical makeup is, by nature, complex and mathematically unmanageable. Relative permeability has been our attempt to lend its aggregate behavior some sense of manageability. This has always been done in a fit-for-purpose manner. What is fit for one context, however, may not be so for the others, and this uncertainty continues to churn out theses, antitheses, and syntheses. Expectedly, even more such activity arises with every improvement in computing capabilities, as is once again evident with advances in machine learning—new tools to handle old problems. That is where my first pick is for you, with some additional suggested readings in references that follow. Data analytics does much more than estimate relative permeability, and the second paper abridged here uses it to predict a flood performance. To allow a break from data science, the third paper chosen deals with the important topic of electromagnetics as applied to reservoir characterization and heating. I hope you find these to be useful and interesting reads.

Hysteresis in Flow in Porous Media With Phase Transitions

1999 ◽  
Author(s):  
Pavel Bedrikovetsky ◽  
Dan Marchesin ◽  
Paulo Roberto Ballin
Keyword(s):  
Porous Media ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Initial Boundary ◽  
Oil Reservoirs ◽  
Flow In Porous Media ◽  
Fractional Flow ◽  
Two Phase ◽  
Initial Boundary Problem ◽  
Gas Drive

Abstract Two-phase flow with hysteresis in porous media is described by the Buckley-Leverett model with three types of fractional flow functions: imbibition, drainage and scanning. The mathematical theory for the Riemann problem and for non-self-similar initial-boundary problem is developed. The structure of the solutions is presented and the physical interpretation of the phenomena is discussed. We obtain the analytical solution for the injection of water slug with gas drive into oil reservoirs. The solutions show that the effect of hysteresis is to decrease gas flux (in the case where the drainage relative permeability lies below the imbibition relative permeability). This effect increases oil recovery for Water-Alternate-Gas injection in oil reservoirs.

scholarly journals Investigation of clogging in porous media induced by microorganisms using a microfluidic application

2021 ◽  
Author(s):  
Calvin Lumban Gaol ◽  
Leonhard Ganzer ◽  
Soujatya Mukherjee ◽  
Hakan Alkan
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Hydrogen Storage ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Aquifer Storage And Recovery ◽  
Aquifer Storage ◽  
Medium Permeability ◽  
Underground Hydrogen Storage

The presence of microorganisms could alter the porous medium permeability, which is vital for several applications, including aquifer storage and recovery (ASR), enhanced oil recovery (EOR) and underground hydrogen storage.

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