scholarly journals Effect of Surface Wettability on Immiscible Displacement in a Microfluidic Porous Media

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 664 ◽  
Author(s):  
Jorge Avendaño ◽  
Nicolle Lima ◽  
Antonio Quevedo ◽  
Marcio Carvalho
Keyword(s):  
Porous Media ◽  
Water Injection ◽  
Residual Oil ◽  
Strong Function ◽  
Fluid Displacement ◽  
Oil Displacement ◽  
Displacement Front ◽  
Final Volume ◽  
Displacement Experiments ◽  
Effect Of Surface

Wettability has a dramatic impact on fluid displacement in porous media. The pore level physics of one liquid being displaced by another is a strong function of the wetting characteristics of the channel walls. However, the quantification of the effect is still not clear. Conflicting data have shown that in some oil displacement experiments in rocks, the volume of trapped oil falls as the porous media becomes less water-wet, while in some microfluidic experiments the volume of residual oil is higher in oil-wet media. The reasons for this discrepancy are not fully understood. In this study, we analyzed oil displacement by water injection in two microfluidic porous media with different wettability characteristics that had capillaries with constrictions. The resulting oil ganglia size distribution at the end of water injection was quantified by image processing. The results show that in the oil-wet porous media, the displacement front was more uniform and the final volume of remaining oil was smaller, with a much smaller number of large oil ganglia and a larger number of small oil ganglia, when compared to the water-wet media.

The Effect of Following Water after Polymer Flooding on the Displacement Efficiency with Alternately Injecting Slug of Gel and Polymer/Surfactant

2013 ◽  
Vol 734-737 ◽  
pp. 1290-1293 ◽  
Author(s):  
Ji Hong Zhang ◽  
Yu Wang ◽  
Xi Ling Chen ◽  
Zi Wei Qu ◽  
Dong Ke Qin
Keyword(s):  
Polymer Flooding ◽  
Experimental Results ◽  
Compound System ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Flat Panel ◽  
Oil Displacement ◽  
Panel Model ◽  
Displacement Experiments ◽  
Polymer Surfactant

Aiming at the development of remaining oil after polymer flooding, the author develops an oil displacement technology, alternately injecting the slug of the gel and polymer/surfactant compound system, which can advanced improve the remained oil after polymer flooding. By using the artificial large flat-panel model, the oil displacement experiments are carried on to study the injection characteristics and the displacement efficiency of the alternately injecting the slug of gel and polymer/surfactant compound system, and whether the following water should be injected after polymer flooding has been discussed. The experimental results show that, the recovery of alternately injecting the gel and polymer/surfactant slug after polymer flooding could enhance recovery more than 10% on the basis of polymer flooding, the following water after polymer flooding has a little impact on the final recovery but increasing time and the difficulty of development. Therefore, these results provide the technology that alternately injecting the slug of the gel and polymer/surfactant could advance develop the residual oil and enhance the recovery after polymer flooding.

Effects of Mobile Water on Multiple-Contact Miscible Gas Displacements

1983 ◽  
Vol 23 (03) ◽  
pp. 447-455 ◽  
Author(s):  
D.L. Tiffin ◽  
W.F. Yellig
Keyword(s):  
Water Saturation ◽  
Water Injection ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Mobile Water ◽  
Oil Displacement ◽  
Oil Displacement Efficiency ◽  
Gas Flooding ◽  
Water Trapping ◽  
First Contact

Abstract Miscible gas flooding using an alternate gas/water injection process (AGWIP) is presently being applied for enhanced oil recovery (EOR) in several waterflooded reservoirs. A mobile-water saturation in the vicinity of the miscible displacement front can occur in this process. To design field applications of miscible gas floods process. To design field applications of miscible gas floods properly, it is necessary to understand the effects of properly, it is necessary to understand the effects of water saturations above the connate saturation on the oil-displacement efficiency. Previous research on AGWIP has involved water-wet long-core flow tests using an injected solvent that is first-contact miscible with the inplace oil. Miscible floods employing CO2, enriched gas, methane, and flue gases, however, are rarely first-contact miscible with reservoir oils; the oil miscibility is normally achieved by a multiple-contact mechanism. This paper discusses the effects of mobile water on multiple-contact miscible displacements under water- and oil-wet conditions. Tests were conducted in 8-ft (244-cm) water- and oil-wet Berea cores in which CO2 and water were injected both separately and simultaneously to displace a reservoir oil. The data presented focus on effects of water in the oil-moving zone (OMZ) where the CO2 is generating miscibility with the oil and mobilizing residual oil to waterflooding. Special emphasis is placed on understanding the effect of mobile-water saturation on the oil-displacement efficiency and the component transfer between phases necessary to develop miscibility in the CO2/reservoir-oil system. This study demonstrates that reservoir wettability is a key factor in the performance of AGWIP. Gas/water injection can, under certain conditions, have adverse effects on characteristics of the OMZ. These effects are in part caused by the water trapping portions of the oil and part caused by the water trapping portions of the oil and solvent. It was observed that mobile water did not change the mass transfer process by which miscibility develops in a multiple-contact miscible displacement. Introduction Miscible gas flooding has been and will be used as a commercial EOR process. In most reservoir applications the injected gas has a lower viscosity than the reservoir oil being displaced. This leads to an inherently unfavorable gas/oil mobility ratio. AGWIP has been used to control mobility. To improve sweep of the injected miscible gas, and to utilize this relatively expensive fluid more effectively. In many field applications of this process, volumes of miscible gas and water are injected process, volumes of miscible gas and water are injected alternately into the reservoir until the desired cumulative slug volume of miscible gas has been injected. The AGWIP process may lead to a high mobile-water saturation in the reservoir, particularly in waterflooded reservoirs. Several authors have discussed the effects of this mobile water on the first-contact miscible oil-displacement process. These studies have shown that the in-place oil can be shielded from the injected solvent by the mobile water in water-wet porous media. The ability of the injected solvent to displace residual oil in laboratory systems was detrimentally affected by high mobile-water saturations. In simulated oil-wet porous media, this solvent trapping was either much less severe or nonexistent. Simulated oil-wet conditions were obtained in a water-wet core by displacing a glycerin/water solution by simultaneous injection of water and oil. SPEJ P. 447

The Effect of Interfacial Tensions on Relative Oil/Water Permeabilities of Consolidated Porous Media

1982 ◽  
Vol 22 (03) ◽  
pp. 371-381 ◽  
Author(s):  
Jude O. Amaefule ◽  
Lyman L. Handy
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Relative Permeability ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Interfacial Tensions ◽  
Oil Displacement ◽  
Oil Water ◽  
Relative Permeability Curves ◽  
Low Tension

Abstract Relative permeabilities of systems containing low- tension additives are needed to develop mechanistic insights as to how injected aqueous chemicals affect fluid distribution and flow behavior. This paper presents results of an experimental investigation of the effect of low interfacial tensions (IFT's) on relative oil/water permeabilities of consolidated porous media. The steady- and unsteady-state displacement methods were used to generate relative permeability curves. Aqueous low-concentration surfactant systems were used to vary IFT levels. Empirical correlations were developed that relate the imbibition relative permeabilities, apparent viscosity, residual oil, and water saturations to the interfacial tension through the capillary number (Nc=v mu / sigma). They require two empirical, experimentally generated coefficients. The experimental results show that the relative oil/water permeabilities at any given saturation are affected substantially by IFT values lower than 10-1 mN/m. Relative oil/water permeabilities increased with decreasing IFT (increasing N ). The residual oil and residual water saturations (S, and S) decreased, while the total relative mobilities increased with decreasing IFT. The correlations predict values of relative oil/water permeability ratios, fractional flow, and residual saturations that agree with our experimental data. Apparent mobility design viscosities decreased exponentially with the capillary number. The results of this study can be used with simulators to predict process performance and efficiency for enhanced oil-recovery projects in which chemicals are considered for use either as waterflood or steamflood additives. However, the combined effect of decreased interfacial tension and increased temperature on relative permeabilities has not yet been studied. Introduction Oil displacement with an aqueous low-concentration surfactant solution is primarily dependent on the effectiveness of the solutions in reducing the IFT between the aqueous phase and the reservoir oil. With the attainment of ultralow IFT's (10 mN/m) and with adequate mobility controls, all the oil contacted can conceivably be displaced. When the interfacial tension is reduced to near zero values, the process tends to approach miscible displacement. However, most high-concentration soluble oil systems revert to immiscible displacement processes as the injected chemical traverses the reservoir. This is a result of the continual depletion of the surfactant by adsorption on the rock and by precipitation with divalent cations in the reservoir brine. The mechanism by which residual oil is mobilized by low-tension displacing fluids cannot be explained solely by the application of Darcy's law to both the aqueous and the oleic phases. On the other hand, in those reservoir regions in which water and oil are flowing concurrently as continuous phases, Darcy's law would be expected to apply and the relative permeability concept would be valid. If a low-tension aqueous phase were to invade a region in which the oil had not as yet been reduced to a discontinuous irreducible saturation, one would expect, also, that the relative permeability concept would be applicable. Under circumstances for which these conditions apply, relative permeabilities at low interfacial tensions would be required, The effect of IFT's on relative permeability curves has received limited treatment in the petroleum literature. Leverett reported a small but definite tendency for a water/oil system in unconsolidated rocks to exhibit 20 to 30% higher relative permeabilities if the IFT was decreased from 24 to 5 mN/m. Mungan studied interfacial effects on oil displacement in Teflons cores. The interfacial tension values varied from 5 to 40 mN/m. SPEJ P. 371^

scholarly journals Suppressing viscous fingering in structured porous media

2018 ◽  
Vol 115 (19) ◽  
pp. 4833-4838 ◽  
Author(s):  
Harris Sajjad Rabbani ◽  
Dani Or ◽  
Ying Liu ◽  
Ching-Yao Lai ◽  
Nancy B. Lu ◽  
...  
Keyword(s):  
Porous Media ◽  
Pore Size ◽  
Hydrodynamic Instability ◽  
Viscous Fingering ◽  
High Viscosity ◽  
Immiscible Displacement ◽  
Interfacial Instabilities ◽  
Fluid Displacement ◽  
Pore Sizes ◽  
Displacement Front

Finger-like protrusions that form along fluid−fluid displacement fronts in porous media are often excited by hydrodynamic instability when low-viscosity fluids displace high-viscosity resident fluids. Such interfacial instabilities are undesirable in many natural and engineered displacement processes. We report a phenomenon whereby gradual and monotonic variation of pore sizes along the front path suppresses viscous fingering during immiscible displacement, that seemingly contradicts conventional expectation of enhanced instability with pore size variability. Experiments and pore-scale numerical simulations were combined with an analytical model for the characteristics of displacement front morphology as a function of the pore size gradient. Our results suggest that the gradual reduction of pore sizes act to restrain viscous fingering for a predictable range of flow conditions (as anticipated by gradient percolation theory). The study provides insights into ways for suppressing unwanted interfacial instabilities in porous media, and provides design principles for new engineered porous media such as exchange columns, fabric, paper, and membranes with respect to their desired immiscible displacement behavior.

Three-Dimensional Visualization of Oil Displacement by Foam in Porous Media

2021 ◽  
Author(s):  
Josiah Siew Kai Wong ◽  
Tetsuya Suekane
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Three Dimensional ◽  
The Other ◽  
Oil Viscosity ◽  
Fluid Displacement ◽  
Oil Displacement ◽  
Gas Flooding ◽  
Displacement Patterns ◽  
Foam In Porous Media

Abstract Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control over the other injection method such as gas flooding, water flooding and other EOR methods. Foam which has high viscosity illustrates great potential for displacing liquid. The relative immobility of foam in porous media seems to be able to suppress the formation of fingers during oil displacement leading a more stable displacement. However, there are still various parameters that may influence the efficiency of foam assisted oil displacement such as oil properties, permeability of reservoir rock, physical and chemical properties of foam, and other parameters. Also, the interaction and displacement patterns of foam inside the porous media are remained unknown. Thus, in this study, we investigated the three-dimensional (3D) characteristics of oil recovery with gases, water, surfactant, and foam injection in a porous media set-up. By using CT scanning machine, the fluid displacement patterns were captured and analyzed. Moreover, the effect of oil viscosity on foam displacement patterns is studied. The study provides a qualitative and quantitative experimental visualization of 3D displacement structure, oil recovery with gases, liquid and foam injection. As a result, the comparison of fluid displacement patterns between gases, water, surfactant and foam injection show that foam has the good ability in sweeping and forms stable displacement front. The combination of surfactant, liquid and gas, which makes up foam resulted in a synergistic effect in oil displacement. On the other hand, viscous fingering, gravity segregation, trapped oil phenomena are shown in gas flooding and liquid flooding experiments. Thus, foam which displaced stably across the permeable bed resulted in the highest oil recovery factor. The mechanism of foam flow in porous media was understood in this study. Foam, as a series of bubble, burst and become free moving liquid and gas particles when in contact with oil and porous media. Therefore, two displacement fronts could be found from the foam injection experiment, in which the front layer moving ahead in contacting with oil bank is the discontinuous gas/liquid layer and followed by stably foam bank at the back. Due to the stable displacement of foam bank, the effect of oil viscosity on foam displacement is suppressed and showed no distinction in terms of displacement patterns. The flow regimes are found to be the same despite different viscosity of displaced oil. There has been no linear correlation proved between the oil viscosity and oil recovery factor.

scholarly journals Laboratory Study of Residual Oil Mobilization by Induce Vibration in Porous Media

2021 ◽  
Vol 1145 (1) ◽  
pp. 012052
Author(s):  
Ali Nooruldeen Abdulkareem ◽  
Mudhfer Yacoub Hussien ◽  
Hanoon H. Mashkoor
Keyword(s):  
Porous Media ◽  
Laboratory Study ◽  
Residual Oil

scholarly journals Quasistatic fluid-fluid displacement in porous media: Invasion-percolation through a wetting transition

2018 ◽  
Vol 3 (10) ◽  
Author(s):  
Bauyrzhan K. Primkulov ◽  
Stephen Talman ◽  
Keivan Khaleghi ◽  
Alireza Rangriz Shokri ◽  
Rick Chalaturnyk ◽  
...  
Keyword(s):  
Porous Media ◽  
Wetting Transition ◽  
Invasion Percolation ◽  
Fluid Displacement

A New Method of Fall-Off Test in Water Injection Well in Tahe Oilfield

2013 ◽  
Vol 807-809 ◽  
pp. 2508-2513
Author(s):  
Qiang Wang ◽  
Wan Long Huang ◽  
Hai Min Xu
Keyword(s):  
Water Injection ◽  
Injection Well ◽  
Well Test ◽  
Well Bore ◽  
Residual Oil ◽  
Injection Wells ◽  
Oil Saturation ◽  
Tahe Oilfield ◽  
Fitting Method ◽  
Front Radius

In pressure drop well test of the clasolite water injection well of Tahe oilfield, through nonlinear automatic fitting method in the multi-complex reservoir mode for water injection wells, we got layer permeability, skin factor, well bore storage coefficient and flood front radius, and then we calculated the residual oil saturation distribution. Through the examples of the four wells of Tahe oilfield analyzed by our software, we found that the method is one of the most powerful analysis tools.

Tertiary Recovery Improvement of Steam Injection Using Chemical Additives: Pore Scale Understanding of Challenges and Solutions Through Visual Experiments

2021 ◽  
Author(s):  
Randy Agra Pratama ◽  
Tayfun Babadagli
Keyword(s):  
Porous Media ◽  
Phase Change ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Phase Distribution ◽  
Steam Injection ◽  
Hot Water ◽  
Heavy Oil Recovery ◽  
Residual Oil ◽  
Tertiary Recovery

Abstract Our previous research, honoring interfacial properties, revealed that the wettability state is predominantly caused by phase change—transforming liquid phase to steam phase—with the potential to affect the recovery performance of heavy-oil. Mainly, the system was able to maintain its water-wetness in the liquid (hot-water) phase but attained a completely and irrevocably oil-wet state after the steam injection process. Although a more favorable water-wetness was presented at the hot-water condition, the heavy-oil recovery process was challenging due to the mobility contrast between heavy-oil and water. Correspondingly, we substantiated that the use of thermally stable chemicals, including alkalis, ionic liquids, solvents, and nanofluids, could propitiously restore the irreversible wettability. Phase distribution/residual oil behavior in porous media through micromodel study is essential to validate the effect of wettability on heavy-oil recovery. Two types of heavy-oils (450 cP and 111,600 cP at 25oC) were used in glass bead micromodels at steam temperatures up to 200oC. Initially, the glass bead micromodels were saturated with synthesized formation water and then displaced by heavy-oils. This process was done to exemplify the original fluid saturation in the reservoirs. In investigating the phase change effect on residual oil saturation in porous media, hot-water was injected continuously into the micromodel (3 pore volumes injected or PVI). The process was then followed by steam injection generated by escalating the temperature to steam temperature and maintaining a pressure lower than saturation pressure. Subsequently, the previously selected chemical additives were injected into the micromodel as a tertiary recovery application to further evaluate their performance in improving the wettability, residual oil, and heavy-oil recovery at both hot-water and steam conditions. We observed that phase change—in addition to the capillary forces—was substantial in affecting both the phase distribution/residual oil in the porous media and wettability state. A more oil-wet state was evidenced in the steam case rather than in the liquid (hot-water) case. Despite the conditions, auspicious wettability alteration was achievable with thermally stable surfactants, nanofluids, water-soluble solvent (DME), and switchable-hydrophilicity tertiary amines (SHTA)—improving the capillary number. The residual oil in the porous media yielded after injections could be favorably improved post-chemicals injection; for example, in the case of DME. This favorable improvement was also confirmed by the contact angle and surface tension measurements in the heavy-oil/quartz/steam system. Additionally, more than 80% of the remaining oil was recovered after adding this chemical to steam. Analyses of wettability alteration and phase distribution/residual oil in the porous media through micromodel visualization on thermal applications present valuable perspectives in the phase entrapment mechanism and the performance of heavy-oil recovery. This research also provides evidence and validations for tertiary recovery beneficial to mature fields under steam applications.

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