scholarly journals Pore-Scale Simulation of Particle Flooding for Enhancing Oil Recovery

Energies ◽  
2021 ◽  
Vol 14 (8) ◽  
pp. 2305
Author(s):  
Xiangbin Liu ◽  
Le Wang ◽  
Jun Wang ◽  
Junwei Su
Keyword(s):  
Oil Recovery ◽  
Flow Behavior ◽  
Ct Scanning ◽  
Water Flooding ◽  
Pore Scale ◽  
Simulation Techniques ◽  
Three Phase ◽  
Remaining Oil ◽  
Three Phase Flow ◽  
Displacement Force

The particles, water and oil three-phase flow behaviors at the pore scale is significant to clarify the dynamic mechanism in the particle flooding process. In this work, a newly developed direct numerical simulation techniques, i.e., VOF-FDM-DEM method is employed to perform the simulation of several different particle flooding processes after water flooding, which are carried out with a porous structure obtained by CT scanning of a real rock. The study on the distribution of remaining oil and the displacement process of viscoelastic particles shows that the capillary barrier near the location with the abrupt change of pore radius is the main reason for the formation of remaining oil. There is a dynamic threshold in the process of producing remaining oil. Only when the displacement force exceeds this threshold, the remaining oil can be produced. The flow behavior of particle–oil–water under three different flooding modes, i.e., continuous injection, alternate injection and slug injection, is studied. It is found that the particle size and the injection mode have an important influence on the fluid flow. On this basis, the flow behavior, pressure characteristics and recovery efficiency of the three injection modes are compared. It is found that by injecting two kinds of fluids with different resistance increasing ability into the pores, they can enter into different pore channels, resulting in the imbalance of the force on the remaining oil interface and formation of different resistance between the channels, which can realize the rapid recovery of the remaining oil.

Influence of Wettability on Residual Gas Trapping and Enhanced Oil Recovery in Three-Phase Flow: A Pore-Scale Analysis by Use of Microcomputed Tomography

SPE Journal ◽  
2016 ◽  
Vol 21 (06) ◽  
pp. 1916-1929 ◽  
Author(s):  
Stefan Iglauer ◽  
Taufiq Rahman ◽  
Mohammad Sarmadivaleh ◽  
Adnan Al-Hinai ◽  
Martin A. Fernø ◽  
...  
Keyword(s):  
Power Law ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Microcomputed Tomography ◽  
Rock Surface ◽  
Phase Flow ◽  
Pore Scale ◽  
Three Phase ◽  
Three Phase Flow ◽  
Capillary Pressures

Summary We imaged an intermediate-wet sandstone in three dimensions at high resolution (1–3.4 µm3) with X-ray microcomputed tomography (micro-CT) at various saturation states. Initially the core was at connate-water saturation and contained a large amount of oil (94%), which was produced by a waterflood [recovery factor Rf = 52% of original oil in place (OOIP)] or a direct gas flood (Rf = 66% of OOIP). Subsequent waterflooding and/or gasflooding (water-alternating-gas process) resulted in significant incremental-oil recovery (Rf = 71% of OOIP), whereas a substantial amount of gas could be stored (approximately 50%)—significantly more than in an analog water-wet plug. The oil- and gas-cluster-size distributions were measured and followed a power-law correlation N ∝ V−τ , where N is the frequency with which clusters of volume V are counted, and with decays exponents τ between 0.7 and 1.7. Furthermore, the cluster volume V plotted against cluster surface area A also correlated with a power-law correlation A ∝ Vp, and p was always ≈ 0.75. The measured τ- and p-values are significantly smaller than predicted by percolation theory, which predicts p ≈ 1 and τ = 2.189; this raises increasing doubts regarding the applicability of simple percolation models. In addition, we measured curvatures and capillary pressures of the oil and gas bubbles in situ, and analyzed the detailed pore-scale fluid configurations. The complex variations in fluid curvatures, capillary pressures, and the fluid/fluid or fluid/fluid/fluid pore-scale configurations (exact spatial locations also in relation to each other and the rock surface) are the origin of the well-known complexity of three-phase flow through rock.

scholarly journals Pore-Scale Imaging and Analysis of Wettability Order, Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

2021 ◽  
Author(s):  
Abdulla Alhosani ◽  
Branko Bijeljic ◽  
Martin J. Blunt
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Pore Space ◽  
Flow In Porous Media ◽  
Phase Flow ◽  
Pore Scale ◽  
Gas Oil ◽  
Capillary Trapping ◽  
Three Phase ◽  
Three Phase Flow

AbstractThree-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.

Sandstone and Carbonate Two- and Three-Phase Relative Permeability Characteristics

1970 ◽  
Vol 10 (01) ◽  
pp. 75-84 ◽  
Author(s):  
F.N. Schneider ◽  
W.W. Owens
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Water Injection ◽  
Phase System ◽  
Phase Flow ◽  
Two Phase ◽  
Permeability Characteristics ◽  
Three Phase ◽  
Three Phase Flow

Abstract Three-phase relative permeability characteristics applicable to various oil displacement processes in the reservoir such as combustion and alternate gas-water injection were determined on both outcrop and reservoir core samples. Steady-state and nonsteady-state tests were performed on a variety of sandstone and carbonate core samples having different wetting properties. Some of the tests were performed on preserved samples. Some of the three-phase tests were performed on samples that contained two flowing phases and a third nonflowing phase, either gas or oil. These were classed as three-phase flow tests because the third phase played an important role in the flow behavior which was determined. The three-phase relative permeability test results are directly compared with the results of two-phase gas-oil and water-oil test. Wetting-phase relative permeability was found to be primarily dependent on its own saturation, i.e., relative permeability to the wetting phase during three-phase flow was in agreement with and could be predicted from the tow-phase data. Nonwetting-phase relative permeability-saturation relationships were found to be more complex and to depend in some cases on the saturation history of both nonwetting phases and on the saturation ratio of the second nonwetting phase and the wetting phases. Trapping of a given nonwetting phase or mutual flow interference between the two nonwetting phases when both are flowing accounts for most of the low relative permeabilities observed for three-phase flow tests. However, in special cases nonwetting-phase relative permeabilities at a given saturation are higher than those given by two-phase flow data. Despite these complexities some types of three-phase flow behavior can be predicted from two-phase flow data. Through its effect on the spatial distribution of the phases, wettability is shown to be a controlling factor in determining three-phase relative permeability characteristics. however, despite the importance of wettability the present data shown that for both water-wet and oil-wet systems oil recovery can be improved by several different injection processes, but the additional oil recovery is accompanied by lower fluid mobility. Introduction The increasing emphasis on optimizing recovery and the rapid and extensive development and use of mathematical modes for predicting reservoir performance are together creating a widespread need for reliable basic data on rock flow behavior. The two-phase imbibition or drainage flow relationships common to conventional oil recovery processes (depletion, gas or water injection, gravity drainage) are not applicable to some of the newer secondary and tertiary recovery techniques. This is because the reservoir displacement process may differ from that easily simulated in laboratory relative permeability studies. in some situations, data are needed fro a three-phase system where almost any combination of two fluids or even all three fluids may be flowing. In other, however, only two flowing phases are present, but the saturation history of the system is unique. Leverett and Lewis were the first to collect experimental relative permeability data on a three-phase system. Corey et al. were similarly leaders in efforts to define three-phase flow relationships using empirical approaches. Space does not permit a critical review of these earlier works. For those interested, a recent article by Saraf and Fatt provides a brief discussion of the experimental techniques used by earlier investigators. Suffice it to say that both experimental and empirical approaches have been used, but the applicability of both has been limited because in only one case have three-phase relative permeability data been obtained on reservoir rock material. SPEJ P. 75ˆ

scholarly journals Flow Dynamics of Sulfate-Modified Water/Polymer Flooding in Micromodels with Modified Wettability

2020 ◽  
Vol 10 (9) ◽  
pp. 3239 ◽  
Author(s):  
Muhammad Tahir ◽  
Rafael E. Hincapie ◽  
Calvin L. Gaol ◽  
Stefanie Säfken ◽  
Leonhard Ganzer
Keyword(s):  
Oil Recovery ◽  
Flow Behavior ◽  
Water Flooding ◽  
Process Efficiency ◽  
Pore Scale ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Flood ◽  
Fluid Interaction

This work describes the flow behavior of the oil recovery obtained by the injection of sulfate-modified/low-salinity water in micromodels with different wettabilities. It provides a detailed microscopic visualization of the displacement taking place during modified water flooding at a pore-scale level, while evaluating the effect of wettability on oil recovery. A comprehensive workflow for the evaluation is proposed that includes fluid–fluid and rock–fluid interactions. The methods studied comprise flooding experiments with micromodels. Artificial and real structure water-wet micromodels are used to understand flow behavior and oil recovery. Subsequently, water-wet, complex-wet, and oil-wet micromodels help understand wettability and rock–fluid interaction. The effect of the sulfate content present in the brine is a key variable in this work. The results of micromodel experiments conducted in this work indicate that sulfate-modified water flooding performs better in mixed-wet/oil-wet (artificial structure) than in water-wet systems. This slightly differs from observations of core flood experiments, where oil-wet conditions provided better process efficiency. As an overall result, sulfate-modified water flooding recovered more oil than SSW injection in oil-wet and complex-wet systems compared to water-wet systems.

Impact of pore-scale three-phase flow for arbitrary wettability on reservoir-scale oil recovery

2014 ◽  
Vol 121 ◽  
pp. 110-121 ◽  
Author(s):  
Adnan Al-Dhahli ◽  
Sebastian Geiger ◽  
Marinus I.J. van Dijke
Keyword(s):  
Oil Recovery ◽  
Phase Flow ◽  
Pore Scale ◽  
Three Phase ◽  
Three Phase Flow

The Research of Flood Pattern Completeness in the Thin and Poor Oil Layers of South West II Area

2012 ◽  
Vol 594-597 ◽  
pp. 2541-2544
Author(s):  
Xiao Hui Wu ◽  
Kao Ping Song ◽  
Chi Dong ◽  
Ji Cheng Zhang ◽  
Jing Fu Deng
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
South West ◽  
Oil Distribution ◽  
Well Pattern ◽  
Remaining Oil ◽  
Tertiary Oil Recovery ◽  
Well Pattern Optimization ◽  
Numerical Simulation Technique

As line well pattern is the main development technique in the thin and poor oil layers of Daqing Oilfield South West Ⅱ PⅠ group, the layers have been idle and the degree of reserve recovery is far less than the region level. In response to these problems, we analyzed the balanced flood performance of various layers and the remaining oil distribution through numerical simulation technique. It shows that, the main remaining oil type of intended layers is caused by voidage-injection imperfection. Considering the needs of the follow-up infill well pattern and tertiary oil recovery, we decided to keep the well network independent and integrated without disturbing the pattern configuration and main mining object of various sets of well pattern. Finally we confirmed to perforate-adding the first infill wells of intended layers to consummate the water flooding regime. Through analyzing the production target of different well pattern optimization programs relatively, it shows that the best program has regular well pattern and large drilled thickness.

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