Pore-Scale Transport Mechanisms and Macroscopic Displacement Effects of In-Situ Oil-in-Water Emulsions in Porous Media

2018 ◽  
Vol 140 (10) ◽  
Author(s):  
Chuan Lu ◽  
Wei Zhao ◽  
Yongge Liu ◽  
Xiaohu Dong
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Mobility Control ◽  
Pore Scale ◽  
Sweep Efficiency ◽  
Emulsion Droplets ◽  
Oil In Water ◽  
Retention Volumes

Oil-in-water (O/W) emulsions are expected to be formed in the process of surfactant flooding for heavy oil reservoirs in order to strengthen the fluidity of heavy oil and enhance oil recovery. However, there is still a lack of detailed understanding of mechanisms and effects involved in the flow of O/W emulsions in porous media. In this study, a pore-scale transparent model packed with glass beads was first used to investigate the transport and retention mechanisms of in situ generated O/W emulsions. Then, a double-sandpack model with different permeabilities was used to further study the effect of in situ formed O/W emulsions on the improvement of sweep efficiency and oil recovery. The pore-scale visualization experiment presented an in situ emulsification process. The in situ formed O/W emulsions could absorb to the surface of pore-throats, and plug pore-throats through mechanisms of capture-plugging (by a single emulsion droplet) and superposition-plugging or annulus-plugging (by multiple emulsion droplets). The double-sandpack experiments proved that the in situ formed O/W emulsion droplets were beneficial for the mobility control in the high permeability sandpack and the oil recovery enhancement in the low permeability sandpack. The size distribution of the produced emulsions proved that larger pressures were capable to displace larger O/W emulsion droplets out of the pore-throat and reduce their retention volumes.

Studies on Foam Flow in the Porous Media in the Last Decade: A Review

2012 ◽  
Vol 616-618 ◽  
pp. 257-262 ◽  
Author(s):  
Ming Ming Lv ◽  
Shu Zhong Wang ◽  
Ze Feng Jing ◽  
Ming Luo
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow In Porous Media ◽  
Balance Model ◽  
Sweep Efficiency ◽  
Foam Flow ◽  
New Findings ◽  
X Ray Computed ◽  
Flow Through

Foam has been used for several decades to decrease the mobility of drive gas or steam, thereby increasing the reservoir sweep efficiency and enhancing the oil recovery. The optimization of the operations requires a thorough understanding of the physical aspects involved in foam flow through porous media. The present paper aims mainly at reviewing experimental and modeling studies on foam flow in porous media particularly during the last decade, to stress the new achievements and highlight the areas that are less understood. X-ray computed tomography (CT) is a useful tool to study in-situ foam behaviors in porous media and new findings were obtained through this technology. The population-balance model was improved in different forms by researchers.

scholarly journals Static and Dynamic Performance of Wet Foam and Polymer-Enhanced Foam in the Presence of Heavy Oil

2018 ◽  
Vol 2 (3) ◽  
pp. 38 ◽  
Author(s):  
Ali Telmadarreie ◽  
Japan Trivedi
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Visual Analysis ◽  
Dynamic Performance ◽  
Static Stability ◽  
Heavy Oil Recovery ◽  
Sweep Efficiency ◽  
Foaming Agents ◽  
Dynamic Experiments

Inadequate sweep efficiency is one of the main concerns in conventional heavy oil recovery processes. Alternative processes are therefore needed to increase heavy oil sweep efficiency. Foam injection has gained interest in conventional oil recovery in recent times as it can control the mobility ratio and improve the sweep efficiency over chemical or gas flooding. However, most of the studies have focused on light crude oil. This study aims to investigate the static and dynamic performances of foam and polymer-enhanced foam (PEF) in the presence of heavy oil. Static and dynamic experiments were conducted to investigate the potential of foam and PEF for heavy oil recovery. Static analysis included foam/PEF stability, decay profile, and image analysis. A linear visual sand pack was used to visualize the performance of CO2 foam and CO2 PEF in porous media (dynamic experiments). Nonionic, anionic, and cationic surfactants were used as the foaming agents. Static stability results showed that the anionic surfactant generated relatively more stable foam, even in the presence of heavy oil. Slower liquid drainage and collapse rates for PEF compared to that of foam were the key observations through foam static analyses. Besides improving heavy oil recovery, the addition of polymer accelerated foam generation and propagation in porous media saturated with heavy oil. Visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to conventional foam flooding. Unlike foam injection, lesser channeling (foam collapse) was observed during PEF injection. The results of this study will open a new insight on the potential of foam, especially polymer-enhanced foam, for oil recovery of those reservoirs with viscous oil.

scholarly journals A Pore-Scale Investigation of Residual Oil Distributions and Enhanced Oil Recovery Methods

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3732 ◽  
Author(s):  
Yaohao Guo ◽  
Lei Zhang ◽  
Guangpu Zhu ◽  
Jun Yao ◽  
Hai Sun ◽  
...  
Keyword(s):  
Porous Media ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Scale Model ◽  
Pore Scale ◽  
Residual Oil ◽  
Sweep Efficiency ◽  
Significant Difference

Water flooding is an economic method commonly used in secondary recovery, but a large quantity of crude oil is still trapped in reservoirs after water flooding. A deep understanding of the distribution of residual oil is essential for the subsequent development of water flooding. In this study, a pore-scale model is developed to study the formation process and distribution characteristics of residual oil. The Navier–Stokes equation coupled with a phase field method is employed to describe the flooding process and track the interface of fluids. The results show a significant difference in residual oil distribution at different wetting conditions. The difference is also reflected in the oil recovery and water cut curves. Much more oil is displaced in water-wet porous media than oil-wet porous media after water breakthrough. Furthermore, enhanced oil recovery (EOR) mechanisms of both surfactant and polymer flooding are studied, and the effect of operation times for different EOR methods are analyzed. The surfactant flooding not only improves oil displacement efficiency, but also increases microscale sweep efficiency by reducing the entry pressure of micropores. Polymer weakens the effect of capillary force by increasing the viscous force, which leads to an improvement in sweep efficiency. The injection time of the surfactant has an important impact on the field development due to the formation of predominant pathway, but the EOR effect of polymer flooding does not have a similar correlation with the operation times. Results from this study can provide theoretical guidance for the appropriate design of EOR methods such as the application of surfactant and polymer flooding.

New Insight on Carbonate-Heavy-Oil Recovery: Pore-Scale Mechanisms of Post-Solvent Carbon Dioxide Foam/Polymer-Enhanced-Foam Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1655-1668 ◽  
Author(s):  
Ali Telmadarreie ◽  
Japan J. Trivedi
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Carbonate Reservoirs ◽  
Heavy Oil Recovery ◽  
Pore Scale ◽  
Sweep Efficiency ◽  
Solvent Injection ◽  
Co2 Foam ◽  
The Matrix ◽  
Heavy Crude

Summary Carbonate reservoirs, deposited in the Western Canadian Sedimentary Basin (WCSB), hold significant reserves of heavy crude oil that can be recovered by nonthermal processes. Solvent, gas, water, and water-alternating-gas (WAG) injections are the main methods for carbonate-heavy-oil recovery in the WCSB. Because of the fractured nature of carbonate formations, many advantages of these production methods are usually in contrast with their low recovery factor. Alternative processes are therefore needed to increase oil-sweep efficiency from carbonate reservoirs. Foam/polymer-enhanced-foam (PEF) injection has gained interest in conventional heavy-oil recovery in recent times. However, the oil-recovery process by foam, especially PEF, in conjunction with solvent injection is less understood in fractured heavy-oil-carbonate reservoirs. The challenge is to understand how the combination of surfactant, gas, and polymer allows us to better access the matrix and efficiently sweep the oil. This study introduces a new approach to access the unrecovered heavy oil in fractured-carbonate reservoirs. Carbon dioxide (CO2) foam and CO2 PEF were used to decrease oil saturation after solvent injection, and their performance was compared with gas injection. A specially designed fractured micromodel was used to visualize the pore-scale phenomena during CO2-foam/PEF injection. In addition, the static bulk performances of CO2 foam/PEF were analyzed in the presence of heavy crude oil. A high-definition camera was used to capture high-quality images. The results showed that in both static and dynamic studies the PEF had high stability. Unlike CO2 PEF, CO2 foam lamella broke much faster and resulted in the collapse of the foam during heavy-oil recovery after solvent flooding. It appeared that foam played a greater role than just gas-mobility control. Foam showed outstanding improvement in heavy-oil recovery over gas injection. The presence of foam bubbles was the main reason to improve heavy-oil-sweep efficiency in heterogeneous porous media. When the foam bubbles advanced through pore throats, the local capillary number increased enough to displace the emulsified oil. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. Overall, CO2 foam and PEF remarkably increased heavy-oil recovery after solvent injection into the fractured reservoir.

Synergistic Effect between Surfactant and Nanoparticles on the Stability of Foam in EOR Processes

SPE Journal ◽  
2020 ◽  
Vol 25 (02) ◽  
pp. 883-894 ◽  
Author(s):  
Chen Qian ◽  
Ali Telmadarreie ◽  
Mingzhe Dong ◽  
Steven Bryant
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Apparent Viscosity ◽  
Foam Stability ◽  
Gas Injection ◽  
Liquid Interface ◽  
Dynamic Tests ◽  
Sweep Efficiency ◽  
Dynamic Conditions

Summary The major challenge in enhanced oil recovery (EOR) by gas injection is poor volumetric sweep efficiency, mainly due to the high gas mobility and reservoir heterogeneity. Injecting gas as a foam increases sweep efficiency, but maintaining foam stability within the reservoir remains a challenge. This research evaluates the synergistic interaction of one type of nanoparticle and a surfactant to increase foam stability, using the concentration ratio of the two components to tune the affinity of the nanoparticle for the gas/liquid interface. We test the capability of the synergistic two-component system to stabilize methane foam and compare it with foam stabilized by surfactants only. A key distinction is the foam stability upon contact with oil, and we explain the observations in static and dynamic conditions. Foam stability was measured in both static (bubble structure) and dynamic (flow through porous media) conditions. In the static test, foam is generated by the shaking method, and foam texture (bubble size and shape) and the decay of foam height with time are indicators of foam stability. To test static stability in the presence of oil, heavy oil is injected into the foam/liquid interface. In dynamic tests, foam is pregenerated before flowing at elevated pressures into sandpacks containing various oil saturations. Normalized pressure gradient and apparent viscosity are the indicators of foam stability and effectiveness for improving oil recovery. The extent to which nanoparticles are covered with surfactant governs the foam stability, in both static and dynamic conditions. Static foam is stable in the presence of oil only if the nanoparticles are partially covered by the surfactant. In the dynamic test, foam stabilized with only the surfactant collapses in the porous media when oil is present. Nanoparticles alone could not generate foam regardless of the presence of oil or salinity, but foam stabilized with nanoparticles partially covered by surfactant is stable in the presence of both residual and initial oil, and foam apparent viscosity could reach up to 400 cp at residual heavy oil condition. In both static and dynamic conditions, nanoparticles completely covered with a bilayer of surfactant do not stabilize foam in the presence of oil. Partially covered nanoparticle foam also demonstrated salt tolerance in both static and dynamic tests, and foam apparent viscosity can reach up to 200 cp with high salinity and residual heavy oil presented. Thus, at appropriate surface coverage, the combination of nanoparticles and surfactant is more effective than either stabilizer alone. The result shows that interaction of surfactant and nanoparticles is important in foam stability in the porous media with oil. In particular, this interaction is synergistic at certain coverage. This type of synergy can provide much more robust mobility control for EOR processes involving gas injection.

scholarly journals Pore-Scale Investigation on the Plugging Behavior of Submicron-Sized Microspheres for Heterogeneous Porous Media with Higher Permeability

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-9
Author(s):  
Yafei Liu ◽  
Jingwen Yang ◽  
Tianjiang Wu ◽  
Yanhong Zhao ◽  
Desheng Zhou ◽  
...  
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heterogeneous Porous Media ◽  
Pore Scale ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Profile Control ◽  
Migration Analysis ◽  
Core Permeability ◽  
Plugging Performance

Reservoir heterogeneity is regarded as one of the main reasons leading to low oil recovery for both conventional and unconventional reservoirs. High-permeability layers or fractures could result in ineffective water or gas injection and generate nonuniform profile. Polymer microspheres have been widely applied for the conformance control to overcome the bypass of injected fluids and improve the sweep efficiency. For the purpose of examining the plugging performance of submicron-sized microspheres in high-permeability porous media, systematic investigations were implemented incorporating macroscale blocking rate tests using core samples and pore-scale water migration analysis via nuclear magnetic resonance (NMR). Experimental results indicate that microsphere particle size dominates the plugging performance among three studied factors and core permeability has the least influence on the plugging performance. Subsequently, microsphere flooding was conducted to investigate its oil recovery capability. Different oil recovery behaviors were observed for cores with different permeability. For cores with lower permeability, oil recovery increased stepwise with microsphere injection whereas for higher permeability cores oil recovery rapidly increased and reached a plateau. This experimental work provides a better understanding on the plugging behavior of microspheres and could be employed as a reference for screening and optimizing the microsphere flooding process for profile control in heterogeneous reservoirs.

Can We Generate Stable Pickering Emulsions Activating Naturally Occurring Nanoparticles in the Reservoir for Cost Effective Heavy-Oil Recovery?

2021 ◽  
Author(s):  
Zhenjie Wang ◽  
Tayfun Babadagli ◽  
Nobuo Maeda
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Cost Effective ◽  
Heavy Oil Recovery ◽  
Pickering Emulsions ◽  
Sweep Efficiency ◽  
Clay Particles ◽  
Naturally Occurring ◽  
The Stability

Abstract Activating naturally occurring nanoparticles in the reservoir (clays) to generate Pickering emulsions results in low-cost heavy oil recovery. In this study, we test the stability of emulsions generated using different types of clays and perform a parametric analysis on salinity, pH, water to oil ratio (WOR), and particle concentration; additionally, we report on a formulation of injected water used to activate the clays found in sandstones to improve oil recovery. First, oil-in-water (O/W) emulsions generated by different clay particles (bentonite and kaolinite) were prepared for both bottle tests and zeta potential measurements, then the stability of dispersion was measured under various conditions (pH and salinity). Heavy crude oils (50 to 170,000 cP) were used for all experiments. The application conditions for these clay types on emulsion generation and stability were examined. Second, sandpacks with known amounts of clays were saturated with heavy-oil samples. Aqueous solutions with various salinity and pH were injected into the oil-saturated sandpack with a pump. The recoveries were monitored while analyzing the produced samples; a systematic comparison of emulsions formed under various conditions (e.g., salinity, pH, WOR, clay type) was presented. Third, glass bead micromodels with known amounts of clays were also prepared to visualize the in-situ behavior of clay particles under various salinity conditions. The transparent mineral oil instead of opaque heavy oil was used in these micromodel tests for better visualization results. Recommendations were made for the most suitable strategies to enhance heavy oil recovery with and without the presence of clay in the porous medium; moreover, conditions and optimal formulations for said recommendations were presented. The bottle tests showed that 3% bentonite can stabilize O/W emulsions under a high WOR (9:1) condition. The addition of 0.04% of NaOH (pH=12) further improved the emulsion stability against salinity. This improvement is because of the activation of natural surfactant in the heavy oil by the added alkali—as confirmed by the minimum interfacial tension (0.17 mN/M) between the oil and 0.04% of the NaOH solution. The sandpack flood experiments showed an improved sweep efficiency caused by the swelling of bentonite when injecting low salinity fluid (e.g., DIW). The micromodel tests showed a wettability change to be more oil-wet under high salinity conditions, and the swelling of bentonite would divert incoming water flow to other unswept areas thus improving sweep efficiency. This paper presents new ideas and recommendations for further research as well as practical applications to generate stable emulsions for improved waterflooding as a cost-effective approach. It was shown that select clays in the reservoir can be activated to act as nanoparticles, but making them generate stable (Pickering) emulsions in-situ to improve heavy-oil recovery requires further consideration.

A Novel Hybrid Solvent-Based Complex Fluid for Enhanced Heavy Oil Recovery

2021 ◽  
Author(s):  
Ali Telmadarreie ◽  
Christopher Johnsen ◽  
Steven L. Bryant
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Apparent Viscosity ◽  
Viscosity Reduction ◽  
Heavy Oil Recovery ◽  
Green Solvent ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Complex Fluid

Abstract This study designs a novel complex fluid (foam/emulsion) using as main components gas, low-toxicity solvents (green solvents) which may promote oil mobilization, and synergistic foam stabilizers (i.e. nanoparticles and surfactants) to improve sweep efficiency. This nanoparticle-enabled green solvent foam (NGS-foam) avoids major greenhouse gas emissions from the thermal recovery process and improves the performance of conventional green solvent-based methods (non-thermal) by increasing the sweep efficiency, utilizing less solvent while producing more oil. Surfactants and nanoparticles were screened in static tests to generate foam in the presence of a water-soluble/oil-soluble solvent and heavy crude oil from a Canadian oil field (1600 cp). The liquid phase of NGS-foam contains surfactant, nanoparticle, and green solvent (GS) all dispersed in the water phase. Nitrogen was used as the gas phase. Fluid flow experiments in porous media with heterogeneous permeability structure mimicking natural environments were performed to demonstrate the dynamic stability of the NGS-foam for heavy oil recovery. The propagation of the pre-generated foam was monitored at 10 cm intervals over the length of porous media (40 cm). Apparent viscosity, pressure gradient, inline measurement of effluent density, and oil recovery were recorded/calculated to evaluate the NGS-foam performance. The outcomes of static experiments revealed that surfactant alone cannot stabilize the green solvent foam and the presence of carefully chosen nanoparticles is crucial to have stable foam in the presence of heavy oil. The results of NGS-foam flow in heterogeneous porous media demonstrated a step-change improvement in oil production such that more than 60% of residual heavy oil was recovered after initial waterflood. This value of residual oil recovery was significantly higher than other scenarios tested in this study (i.e. GS- water and gas co-injection, conventional foam without GS, GS-foam stabilized with surfactant only and GS-waterflood). The increased production occurred because NGS-foam remained stable in the flowing condition, improves the sweep efficiency and increases the contact area of the solvent with oil. The latter factor is significant: comparing to GS-waterflood, NGS-foam produces a unit volume of oil faster with less solvent and up to 80% less water. Consequently, the cost of solvent per barrel of incremental oil will be lower than for previously described solvent applications. In addition, due to its water solubility, the solvent can be readily recovered from the reservoir by post flush of water and thus re-used. The NGS-foam has several potential applications: recovery from post-CHOPS reservoirs (controlling mobility in wormholes and improving the sweep efficiency while reducing oil viscosity), fracturing fluid (high apparent viscosity to carry proppant and solvent to promote hydrocarbon recovery from matrix while minimizing water invasion), and thermal oil recovery (hot NGS-foam for efficient oil viscosity reduction and sweep efficiency improvement).

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