Wettability Alteration and Foam Mobility Control in a Layered, 2D Heterogeneous Sandpack

SPE Journal ◽  
2012 ◽  
Vol 17 (04) ◽  
pp. 1207-1220 ◽  
Author(s):  
Robert F. Li ◽  
George J. Hirasaki ◽  
Clarence A. Miller ◽  
Shehadeh K. Masalmeh
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Weight Ratio ◽  
Mobility Control ◽  
Wettability Alteration ◽  
Viscous Force ◽  
Layered System ◽  
Low Permeability ◽  
Foaming Agent ◽  
Original Oil In Place

Summary In a layered, 2D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil in place (OOIP) because of injected water flowing through the high-permeability zone, leaving the low-permeability zone unswept. To enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultralow values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical countercurrent flow then exchanged fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foam flood was 94.6% OOIP, even though foam strength was weak. Recovery with chemical flood (incremental recovered oil/waterflood remaining oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous-force-dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI (NIB) at a weight ratio of 1:2 (NI:lauryl betaine) made the new blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT-reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1D homogeneous sandpacks and in an oil-wet heterogeneous layered system with a 34:1 permeability ratio.

Recent Advances in Surfactant EOR

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 889-907 ◽  
Author(s):  
George J. Hirasaki ◽  
Clarence A. Miller ◽  
Maura Puerto
Keyword(s):  
Phase Separation ◽  
Crude Oil ◽  
Oil Recovery ◽  
Surfactant Solution ◽  
Naphthenic Acids ◽  
Mobility Control ◽  
Wettability Alteration ◽  
Recent Advances ◽  
Carbonate Formations

Summary In this paper, recent advances in surfactant enhanced oil recovery (EOR) are reviewed. The addition of alkali to surfactant flooding in the 1980s reduced the amount of surfactant required, and the process became known as alkaline/surfactant/polymer flooding (ASP). It was recently found that the adsorption of anionic surfactants on calcite and dolomite can also be significantly reduced with sodium carbonate as the alkali, thus making the process applicable for carbonate formations. The same chemicals are also capable of altering the wettability of carbonate formations from strongly oil-wet to preferentially water-wet. This wettability alteration in combination with ultralow interfacial tension (IFT) makes it possible to displace oil from preferentially oil-wet carbonate matrix to fractures by oil/water gravity drainage. The alkaline/surfactant process consists of injecting alkali and synthetic surfactant. The alkali generates soap in situ by reaction between the alkali and naphthenic acids in the crude oil. It was recently recognized that the local ratio of soap/surfactant determines the local optimal salinity for minimum IFT. Recognition of this dependence makes it possible to design a strategy to maximize oil recovery with the least amount of surfactant and to inject polymer with the surfactant without phase separation. An additional benefit of the presence of the soap component is that it generates an oil-rich colloidal dispersion that produces ultralow IFT over a much wider range of salinity than in its absence. It was once thought that a cosolvent such as alcohol was necessary to make a microemulsion without gel-like phases or a polymer-rich phase separating from the surfactant solution. An example of an alternative to the use of alcohol is to blend two dissimilar surfactants: a branched alkoxylated sulfate and a double-tailed, internal olefin sulfonate. The single-phase region with NaCl or CaCl2 is greater for the blend than for either surfactant alone. It is also possible to incorporate polymer into such aqueous surfactant solutions without phase separation under some conditions. The injected surfactant solution has underoptimum phase behavior with the crude oil. It becomes optimum only as it mixes with the in-situ-generated soap, which is generally more hydrophobic than the injected surfactant. However, some crude oils do not have a sufficiently high acid number for this approach to work. Foam can be used for mobility control by alternating slugs of gas with slugs of surfactant solution. Besides effective oil displacement in a homogeneous sandpack, it demonstrated greatly improved sweep in a layered sandpack.

scholarly journals Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

2021 ◽  
Author(s):  
Xu-Guang Song ◽  
Ming-Wei Zhao ◽  
Cai-Li Dai ◽  
Xin-Ke Wang ◽  
Wen-Jiao Lv
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Liquid Interface ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Low Permeability ◽  
Oil Water ◽  
Solid Liquid

AbstractThe ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention. In this work, the active silica nanofluids were prepared by modified active silica nanoparticles and surfactant BSSB-12. The dispersion stability tests showed that the hydraulic radius of nanofluids was 58.59 nm and the zeta potential was − 48.39 mV. The active nanofluids can simultaneously regulate liquid–liquid interface and solid–liquid interface. The nanofluids can reduce the oil/water interfacial tension (IFT) from 23.5 to 6.7 mN/m, and the oil/water/solid contact angle was altered from 42° to 145°. The spontaneous imbibition tests showed that the oil recovery of 0.1 wt% active nanofluids was 20.5% and 8.5% higher than that of 3 wt% NaCl solution and 0.1 wt% BSSB-12 solution. Finally, the effects of nanofluids on dynamic contact angle, dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofluids at solid–liquid and liquid–liquid interface. The oil detaching and transporting are completed by synergistic effect of wettability alteration and interfacial tension reduction. The findings of this study can help in better understanding of active nanofluids for EOR in ultra-low permeability reservoirs.

A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs

2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Low Permeability ◽  
High Permeability ◽  
Matrix Permeability ◽  
Rock Heterogeneity ◽  
The Matrix ◽  
Flow Through ◽  
Main Factors

Abstract Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.

Effect and Mechanism of CO2 Electrochemical Reduction for CCUS-EOR

2021 ◽  
Author(s):  
Rukaun Chai ◽  
Yuetian Liu ◽  
Qianjun Liu ◽  
Xuan He ◽  
Pingtian Fan
Keyword(s):  
Contact Angle ◽  
Crude Oil ◽  
Electrochemical Reduction ◽  
1H Nmr ◽  
Oil Recovery ◽  
Co2 Sequestration ◽  
Sno2 Nanoparticles ◽  
Wettability Alteration ◽  
X Ray ◽  
Electrochemical Conversion

Abstract Unconventional reservoir plays an increasingly important role in the world energy system, but its recovery is always quite low. Therefore, the economic and effective enhanced oil recovery (EOR) technology is urgently required. Moreover, with the aggravation of greenhouse effect, carbon neutrality has become the human consensus. How to sequestrate CO2 more economically and effectively has aroused wide concerns. Carbon Capture, Utilization and Storage (CCUS)-EOR is a win-win technology, which can not only enhance oil recovery but also increase CO2 sequestration efficiency. However, current CCUS-EOR technologies usually face serious gas channeling which finally result in the poor performance on both EOR and CCUS. This study introduced CO2 electrochemical conversion into CCUS-EOR, which successively combines CO2 electrochemical reduction and crude oil electrocatalytic cracking both achieves EOR and CCUS. In this study, multiscale experiments were conducted to study the effect and mechanism of CO2 electrochemical reduction for CCUS-EOR. Firstly, the catalyst and catalytic electrode were synthetized and then were characterized by using scanning electron microscope (SEM) & energy dispersive X-ray spectroscopy (EDS) and X-ray photoelectron spectroscopy (XPS). Then, electrolysis experiment & liquid-state nuclear magnetic resonance (1H NMR) experiments were implemented to study the mechanism of CO2 electrochemical reduction. And electrolysis experiment & gas chromatography (GC) & viscosity & density experiments were used to investigate the mechanism of crude oil electrocatalytic cracking. Finally, contact angle and coreflooding experiments were respectively conducted to study the effect of the proposed technology on wettability and CCUS-EOR. SEM & EDS & XPS results confirmed that the high pure SnO2 nanoparticles with the hierarchical, porous structure, and the large surface area were synthetized. Electrolysis & 1H NMR experiment showed that CO2 has converted into formate with the catalysis of SnO2 nanoparticles. Electrolysis & GC & Density & Viscosity experiments indicated that the crude oil was electrocatalytically cracked into the light components (<C20) from the heavy components (C21∼C37). As voltage increases from 2.0V to 7.0V, the intensity of CO2 electrocchemical reduction and crude oil electrocatalytic cracking enhances to maximum at 3.5V (i.e., formate concentration reaches 6.45mmol/L and carbon peak decreases from C17 to C15) and then weakens. Contact angle results indicated that CO2 electrochemical reduction and crude oil electocatalytic cracking work jointly to promote wettability alteration. Thereof, CO2 electrochemical reduction effect is dominant. Coreflooding results indicated that CO2 electrochemical reduction technology has great potential on EOR and CCUS. With the SnO2 catalytic electrode at optimal voltage (3.5V), the additional recovery reaches 9.2% and CO2 sequestration efficiency is as high as 72.07%. This paper introduced CO2 electrochemical conversion into CCUS-EOR, which successfully combines CO2 electrochemical reduction and crude oil electrocatalytic cracking into one technology. It shows great potential on CCUS-EOR and more studies are required to reveal its in-depth mechanisms.

Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽  
2018 ◽  
Vol 23 (03) ◽  
pp. 803-818 ◽  
Author(s):  
Mehrnoosh Moradi Bidhendi ◽  
Griselda Garcia-Olvera ◽  
Brendon Morin ◽  
John S. Oakey ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Water Chemistry ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Field Trials ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

Transport Modelling of Multi-Phase Fluid Flow in Porous Media for Enhanced Oil Recovery

2020 ◽  
Vol 400 ◽  
pp. 38-44
Author(s):  
Hassan Soleimani ◽  
Hassan Ali ◽  
Noorhana Yahya ◽  
Beh Hoe Guan ◽  
Maziyar Sabet ◽  
...  
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Constitutive Relations ◽  
Mobility Control ◽  
Flow In Porous Media ◽  
Wettability Alteration ◽  
Adsorption Effect ◽  
Phase Fluid

This article studies the combined effect of spatial heterogeneity and capillary pressure on the saturation of two fluids during the injection of immiscible nanoparticles. Various literature review exhibited that the nanoparticles are helpful in enhancing the oil recovery by varying several mechanisms, like wettability alteration, interfacial tension, disjoining pressure and mobility control. Multiphase modelling of fluids in porous media comprise balance equation formulation, and constitutive relations for both interphase mass transfer and pressure saturation curves. A classical equation of advection-dispersion is normally used to simulate the fluid flow in porous media, but this equation is unable to simulate nanoparticles flow due to the adsorption effect which happens. Several modifications on computational fluid dynamics (CFD) have been made to increase the number of unknown variables. The simulation results indicated the successful transportation of nanoparticles in two phase fluid flow in porous medium which helps in decreasing the wettability of rocks and hence increasing the oil recovery. The saturation, permeability and capillary pressure curves show that the wettability of the rocks increases with the increasing saturation of wetting phase (brine).

Characteristics of a Geobacillus sp. as an Enhanced Oil Recovery Material

2012 ◽  
Vol 496 ◽  
pp. 542-545
Author(s):  
Xiang Ping Kong
Keyword(s):  
Crude Oil ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Sewage Treatment ◽  
Core Flooding ◽  
Treatment Technology ◽  
Promising Candidate ◽  
Different Types ◽  
Displacement Experiments ◽  
Original Oil In Place

The enhanced oil recovery characteristics of a Geobacillus sp. was investigated by shake flask experiments, blind-tube oil displacement experiments and core flooding tests. The strain exhibited good properties such as resisting high temperature, taking different types of crude oil as the sole carbon source, reducing the viscosity of crude oil, emulsifying and dispersing crude oil or liquid wax. The oil in the dead area could be effectively driven out by the strain, and the oil recovery of original oil in place had been increased by 12.9-15.9% after 5 treatments in 50 days by adopting air-assistant technique (air/liquid 10:1, v/v) due to the synergistic effect of the bacteria and their metabolites such as biogas and biosurfactants. The strain seems to be a promising candidate for microbial enhanced oil recovery and underground sewage treatment technology.

scholarly journals Synthesis and Characterization of Polymeric Surfactant from Palm Oil Methyl Ester and Vinyl Acetate for Chemical Flooding

REAKTOR ◽  
2021 ◽  
Vol 21 (2) ◽  
pp. 65-73
Author(s):  
Agam Duma Kalista Wibowo ◽  
Pina Tiani ◽  
Lisa Aditya ◽  
Aniek Sri Handayani ◽  
Marcelinus Christwardana
Keyword(s):  
Methyl Ester ◽  
Interfacial Tension ◽  
Vinyl Acetate ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Mobility Control ◽  
Wettability Alteration ◽  
Polymeric Surfactant ◽  
Chemical Flooding

Surfactants for enhanced oil recovery are generally made from non-renewable petroleum sulfonates and their prices are relatively expensive, so it is necessary to synthesis the bio-based surfactants that are renewable and ecofriendly. The surfactant solution can reduce the interfacial tension (IFT) between oil and water while vinyl acetate monomer has an ability to increase the viscosity as a mobility control. Therefore, polymeric surfactant has both combination properties in reducing the oil/water IFT and increasing the viscosity of the aqueous solution simultaneously. Based on the study, the Critical Micelle Concentration (CMC) of Polymeric Surfactant was at 0.5% concentration with an IFT of 7.72x10-2 mN/m. The best mole ratio of methyl ester sulfonate to vinyl acetate for polymeric surfactant synthesis was 1:0.5 with an IFT of 6.7x10-3 mN/m. Characterization of the product using FTIR and HNMR has proven the creation of polymeric surfactant. Based on the wettability alteration study, it confirmed that the product has an ability to alter from the initial oil-wet to water-wet quartz surface. In conclusion, the polymeric surfactant has ultralow IFT and could be an alternative surfactant for chemical flooding because the IFT value met with the required standard for chemical flooding ranges from 10-2 to 10-3 mN/m.Keywords: Enhanced Oil recovery, Interfacial Tension, Methyl Ester Sulfonate, Polymeric surfactant, vinyl acetate

scholarly journals A Laboratory Approach on the Hybrid-Enhanced Oil Recovery Techniques with Different Saline Brines in Sandstone Reservoirs

Processes ◽  
2020 ◽  
Vol 8 (9) ◽  
pp. 1051 ◽  
Author(s):  
Yisheng Hu ◽  
Qiurong Cheng ◽  
Jinping Yang ◽  
Lifeng Zhang ◽  
Afshin Davarpanah
Keyword(s):  
Oil Recovery ◽  
Foam Stability ◽  
Oil Production ◽  
Mobility Control ◽  
Recovery Factor ◽  
Wettability Alteration ◽  
Bulk Solution ◽  
Formation Water ◽  
Sandstone Reservoirs ◽  
Brine Injection

As foams are not thermodynamically stable and might be collapsed, foam stability is defined by interfacial properties and bulk solution. In this paper, we investigated foam injection and different salinity brines such as NaCl, CaCl2, KCl, and MgCl2 to measure cumulative oil production. According to the results of this experiment, it is concluded that sequential low-salinity water injections with KCl and foam flooding have provided the highest cumulative oil production in sandstone reservoirs. This issue is related to high wettability changes that had been caused by the KCl. As K+ is a monovalent cation, KCl has the highest wettability changes compared to other saline brines and formation water at 1000 ppm, which is due to the higher wettability changes of potassium (K+) over other saline ions. The interfacial tension for KCl at the lowest value is 1000 ppm and, for MgCl2, has the highest value in this concentration. Moreover, the formation brine, regarding its high value of salty components, had provided lower cumulative oil production before and after foam injection as it had mobilized more in the high permeable zones and, therefore, large volumes of oil would be trapped in the small permeable zones. This was caused by the low wettability alteration of the formation brine. Thereby, formation water flowed in large pores and the oil phase remained in small pores and channels. On the other hand, as foams played a significant role in the mobility control and sweep efficiency, at 2 pore volume, foam increased the pressure drop dramatically after brine injection. Consequently, foam injection after KCl brine injection had the maximum oil recovery factor of 63.14%. MgCl2 and formation brine had 41.21% and 36.51% oil recovery factor.

scholarly journals Design and formulation of surfactant stabilized O/W emulsion for application in enhanced oil recovery: effect of pH, salinity and temperature

2020 ◽  
Vol 75 ◽  
pp. 72
Author(s):  
Narendra Kumar ◽  
Saif Ali ◽  
Amit Kumar ◽  
Ajay Mandal
Keyword(s):  
Crude Oil ◽  
Experimental Model ◽  
Enhanced Oil Recovery ◽  
Droplet Size ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Wettability Alteration ◽  
Independent Variables ◽  
Significant Difference ◽  
Reservoir Conditions

Mobilization of crude oil from the subsurface porous media by emulsion injection is one of the Chemical Enhanced Oil Recovery (C-EOR) techniques. However, deterioration of emulsion by phase separation under harsh reservoir conditions like high salinity, acidic or alkaline nature and high temperature pose a challenge for the emulsion to be a successful EOR agent. Present study aims at formulation of Oil-in-Water (O/W) emulsion stabilized by Sodium Dodecyl Sulfate (SDS) using the optimum values of independent variables – salinity, pH and temperature. The influence of above parameters on the physiochemical properties of the emulsion such as average droplet size, zeta (ζ) potential, conductivity and rheological properties were investigated to optimize the properties. The influence of complex interactions of independent variables on emulsion characteristics were premeditated by experimental model obtained by Taguchi Orthogonal Array (TOA) method. Accuracy and significance of the experimental model was verified using Analysis Of Variance (ANOVA). Results indicated that the experimental models were significantly (p < 0.05) fitted with main influence of salinity (making it a critical variable) followed by its interactions with pH and temperature for all the responses studied for the emulsion properties. No significant difference between the predicted and experimental response values of emulsion ensured the adequacy of the experimental model. Formulated optimized emulsion manifested good stability with 2417.73 nm droplet size, −72.52 mV ζ-potential and a stable rheological (viscosity and viscoelastic) behavior at extensive temperature range. Ultralow Interfacial Tension (IFT) value of 2.22E-05 mN/m was obtained at the interface of crude oil and the emulsion. A favorable wettability alteration of rock from intermediate-wet to water-wet was revealed by contact angle measurement and an enhanced emulsification behavior with crude oil by miscibility test. A tertiary recovery of 21.03% of Original Oil In Place (OOIP) was obtained on sandstone core by optimized emulsion injection. Therefore, performance assessment of optimized emulsion under reservoir conditions confirms its capability as an effective oil-displacing agent.

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