Foam Generation in the Presence of Residual Oil in Porous Media

2021 ◽  
Author(s):  
Muhammad Almajid ◽  
Anthony Kovscek
Keyword(s):  
Capillary Pressure ◽  
Initial Conditions ◽  
Surrounding Medium ◽  
Pore Network ◽  
Liquid Volume ◽  
Residual Oil ◽  
Emulsified Oil ◽  
Foam Generation ◽  
Level Model ◽  
Pore Level

Abstract This paper studies the effect of trapped, emulsified oil on the requirement for the geometrical Roof snap-off for foam generation in a porous medium. We extend an existing hydrodynamic pore-level model to describe the liquid accumulation in an appropriately-sized pore in the presence of oil. The effect of oil is simulated by adjusting the pore shape to be asymmetrical as observed in microfluidic experiments with residual oil. We alter the boundary and initial conditions of the problem to test various scenarios. Specifically, four cases are presented. The liquid accumulation is presented when the amount of wetting liquid volume connected to the pore is altered through changing the boundary conditions (cases 1 and 2). Moreover, the effect of drier surrounding medium and/or drier pores is also tested by increasing either the capillary pressure surrounding the pore or the capillary pressure of the pore itself (cases 3 and 4). We find that the presence of residual oil affects the liquid accumulation times when there is no external liquid pressure gradient applied. Additionally, residual oil presence makes the Roof snap-off criterion for liquid accumulation stricter. To augment our pore-level study, we use a statistical pore network to observe the effect of the microscopic changes observed in our pore-level model macroscopically. Our results indicate that a stricter Roof snap-off criterion leads to fewer germination sites for lamellae generation. Our pore network analysis computes the generation rate constant to be as much as four times larger in the absence of oil than in its presence. Results suggest that changes to the shape of pore constrictions by emulsified oil reduce the effectiveness of foam generation.

Relationship between Residual Saturations and Wettability using Pore-Network Modeling

2021 ◽  
Author(s):  
Prakash Purswani ◽  
Russell T. Johns ◽  
Zuleima T. Karpyn
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Network Modeling ◽  
Pore Network ◽  
Residual Oil ◽  
Residual Saturation ◽  
Oil Saturation ◽  
Pore Network Modeling ◽  
Residual Oil Saturation ◽  
Eor Processes

Abstract The relationship between residual saturation and wettability is critical for modeling enhanced oil recovery (EOR) processes. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Coreflooding experiments have shown that residual oil saturation trends against wettability indices typically show a minimum around mixed-wet conditions. Amott indices, however, provides an average measure of wettability (contact angle), which are intrinsically dependent on a variety of factors such as the initial oil saturation, aging conditions, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore network modeling (PNM), we show that residual oil saturation varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the residual oil saturation decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, calculation of Amott indices for the PNM data sets show that a plot of the residual oil saturation versus Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. This can have important implications for low salinity waterflooding or other EOR processes where wettability is altered.

Application of Meshless Pore-Level Model to Pyrolysis and Synthesis of Nuclear Fuels

2007 ◽  
Author(s):  
Xiaolin Wang ◽  
Hui Zhang ◽  
Lili Zheng
Keyword(s):  
Material Processing ◽  
Transport Phenomena ◽  
Nuclear Material ◽  
Processing Technique ◽  
System Level ◽  
Scale Model ◽  
Nuclear Fuels ◽  
Particle Hydrodynamics ◽  
Level Model ◽  
Pore Level

Uranium-ceramic nuclear fuels can be fabricated through pyrolysis-based materials processing technique. This technique requires lower energy compared to sintering route. During the fabrication process, the source material changes composition continuously and chemical reactions and transport phenomena vary accordingly. Therefore, to obtain such nuclear fuel materials with high uniformity of microstructure/species without crack, transport phenomena in the material processing needs to be better understood. A system-scale model has been developed to account for the pyrolysis-based uranium-ceramic nuclear material processing in our prior work. In this study, a pore-scale numerical model based on Smoothed Particle Hydrodynamics (SPH) will be described for modeling the synthesis of SiC matrix and U3O8. The system-level model provides thermal boundary conditions to the pore-level model. The microstructure and compositions of the produced composites will be studied. Since the control of process temperature plays an important role in the material quality, the effects of heating rate and U3O8 particle size and volume on species uniformity and microstructure are investigated.

Distribution of the Oil Phase Obtained Upon Imbibition of Water

1964 ◽  
Vol 4 (01) ◽  
pp. 49-55 ◽  
Author(s):  
Pietro Raimondi ◽  
Michael A. Torcaso
Keyword(s):  
Primary Production ◽  
Relative Permeability ◽  
Water Saturation ◽  
Initial Conditions ◽  
Flow Behavior ◽  
Phase System ◽  
Residual Oil ◽  
Two Phase ◽  
Connate Water ◽  
Phase Water

Abstract The distribution of the oil phase in Berea sandstone resulting from increasing and decreasing the water saturation by imbibition was investigated Three types of distribution were recognized: trapped, normal and lagging. The amount of oil in each of these distributions was determined as a function of saturation by carrying out a miscible displacement in the oil phase under steady-state conditions of saturation. These conditions were maintained by flowing water and oil simultaneously in given ratios and by using a displacing solvent having essentially the same density and viscosity as the oil.A correlation shows the amount of trapped oil at any saturation to be directly proportional to the conventional residual oil saturation Sir The factor of proportionality is related to the fractional permeability to the water phase. Part of the oil which was not trapped was displaced in a piston- like manner (normal part) and part was eluted gradually (lagging part). The observed phenomena are more than of mere academic importance. Oil which is trapped may well provide the fuel essential for forward combustion and thus be beneficial. On the contrary, in tertiary recovery operations, it is this trapped oil which seems to make current techniques uneconomic. Introduction A typical oilfield may initially contain connate water and oil. After a period of primary production water often enters the field either from surrounding aquifers or from surface injection. During primary production evolution and establishment of a free gas saturation usually occurs. The effect and importance of this third phase is fully recognized. However, this investigation is limited to a two- phase system, one wetting phase (water) and one non-wetting phase (oil). The increase in water content of a water-wet system is termed imbibition. In a relative permeability-saturation diagram such as the one shown in Fig. 1, the initial conditions of the field would he represented by a point below a water saturation of about 35 per cent, i.e., where the imbibition and the drainage curves to the non-wetting phase nearly coincide. When water enters the field the relative permeability to oil decreases along the imbibition curve. At watered-out conditions the relative permeability to the oil becomes zero. At this point a considerable amount of oil, called residual oil, (about 35 per cent in Fig. 1) remains unrecovered. Any attempt to produce this oil will require that its saturation be increased. In Fig. 1 this would mean retracing the imbibition curve upwards. In addition, processes like alcohol and fire flooding, which can be employed at any stage of production, involve the complete displacement of connate water and an increase, or imbibition, of water saturation ahead of the displacing front. Thus, in several types of oil production it is the imbibition-relative permeability curve which rules the flow behavior. For this reason a knowledge of the distribution of the non-wetting phase, as obtained through imbibition, whether "coming down" or "going up" on the imbibition curve, is important. SPEJ P. 49^

Pore Network and Morphological Characterization of Pore-Level Structures

2017 ◽  
Author(s):  
Peyman Mohammadmoradi ◽  
Farzad Bashtani ◽  
Banafsheh Goudarzi ◽  
Saeed Taheri ◽  
Apostolos Kantzas
Keyword(s):  
Pore Network ◽  
Morphological Characterization ◽  
Pore Level

scholarly journals Foam Generation in Flow Across a Sharp Permeability Transition: Effect of Velocity and Fractional Flow

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 451-464 ◽  
Author(s):  
Swej Y. Shah ◽  
Herru As Syukri ◽  
Karl-Heinz Wolf ◽  
Rashidah M. Pilus ◽  
William R. Rossen
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Permeability Transition ◽  
Fractional Flow ◽  
Local Pressure ◽  
The Core ◽  
Foam Generation ◽  
Gas Mobility ◽  
Foam Propagation ◽  
Strong Foam

Summary Foam reduces gas mobility and can help improve sweep efficiency in an enhanced-oil-recovery (EOR) process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that the local pressure gradient exceed a critical value (▿Pmin). Normally, this happens only in the near-well region. Away from wells, these requirements might not be met, and foam propagation is uncertain. It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (Rossen 1999). The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of fractional flow on this process. This article is an extension of a recent study (Shah et al. 2018) investigating the effect of permeability contrast on this process. In this study, the effects of fractional flow and total superficial velocity are described. Coreflood experiments were performed in a cylindrical sintered-glass porous medium with two homogeneous layers and a sharp permeability jump in between, representing a lamination or cross lamination. Unlike previous studies of this foam-generation mechanism, in this study, gas and surfactant solution were coinjected at field-like velocities into a medium that was first flooded to steady state with gas/brine coinjection. The pressure gradient is measured across several sections of the core. X-ray computed tomography (CT) is used to generate dynamic phase-saturation maps as foam generates and propagates through the core. We investigate the effects of velocity and injected-gas fractional flow on foam generation and mobilization by systematically changing these variables through multiple experiments. The core is thoroughly cleaned after each experiment to remove any trapped gas and to ensure no hysteresis. Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, and it then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities. Foam was generated in all cases, at all the injected conditions tested; however, at the lowest velocity tested, strong foam did not propagate all the way to the outlet of the core. Although foam generation was triggered across the permeability boundary at this velocity, it appeared that, for our system, the limit of foam propagation, in terms of a minimum-driving-force requirement, was reached at this low rate. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate—probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ▿P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injection rate.

scholarly journals Validation of pore network modeling for determination of two-phase transport in fibrous porous media

2020 ◽  
Vol 10 (1) ◽  
Author(s):  
Xiang Huang ◽  
Wei Zhou ◽  
Daxiang Deng
Keyword(s):  
Porous Media ◽  
Capillary Pressure ◽  
Network Modeling ◽  
Pore Network ◽  
Lattice Boltzmann Model ◽  
Two Phase ◽  
Throat Radius ◽  
Equivalent Radius ◽  
Pore Network Modeling ◽  
The Cost

AbstractPore network modeling (PNM) has been widely investigated in the study of multiphase transport in porous media due to its high computational efficiency. The advantage of PNM is achieved in part at the cost of using simplified geometrical elements. Therefore, the validation of pore network modeling needs further verification. A Shan-Chen (SC) multiphase lattice Boltzmann model (LBM) was used to simulate the multiphase flow and provided as the benchmark. PNM using different definitions of throat radius was performed and compared. The results showed that the capillary pressure and saturation curves agreed well when throat radius was calculated using the area-equivalent radius. The discrepancy of predicted phase occupations from different methods was compared in slice images and the reason can be attributed to the capillary pressure gradients demonstrated in LBM. Finally, the relative permeability was also predicted using PNM and provided acceptable predictions when compared with the results using single-phase LBM.

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