Foams With Wettability-Altering Capabilities for Oil-Wet Carbonates: A Synergistic Approach

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1126-1139 ◽  
Author(s):  
Robin Singh ◽  
Kishore K. Mohanty
Keyword(s):  
Contact Angle ◽  
Crude Oil ◽  
Anionic Surfactant ◽  
Volume Fraction ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Alpha Olefin Sulfonate ◽  
Zwitterionic Surfactant ◽  
Oil Displacement ◽  
Displacement Experiments

Summary The goal of this work is to systematically study the effect of wettability alteration and foaming, either acting individually or synergistically, on tertiary oil recovery in oil-wet carbonate cores. Three types of anionic-surfactant formulations were used: alkyl propoxy sulfate (APS), which exhibited low interfacial tension (IFT), wettability alteration, and weak foaming; alpha-olefin sulfonate (AOS), which showed no wettability alteration but good foaming; and a blend of APS, AOS, and a zwitterionic-foam booster, which showed low IFT, wettability alteration, and good foaming. First, contact-angle experiments were conducted on oil-wet calcite plates to evaluate their wettability-altering capabilities. Second, spontaneous imbibitions in a microchannel were performed to study the role of IFT reduction and wettability alteration by these formulations. Third, static foam tests were conducted to evaluate their foaming performance in bulk. Fourth, foam-flow experiments were conducted in cores to evaluate potential synergism between the anionic-surfactant AOS and the zwitterionic surfactants in stabilizing foam in the absence of crude oil. Finally, oil-displacement experiments were performed by use of a vuggy, oil-wet, dolomite core saturated with a crude oil. After secondary waterfloods, surfactant solutions were coinjected with methane gas at a fixed foam quality (gas-volume fraction). Contact-angle and spontaneous-imbibition experiments showed that AOS can act as a wettability-altering surfactant in the presence of sodium carbonate, but not alone. No synergy was observed in foam stabilization by means of the blend of zwitterionic surfactant and AOS solution (1:1) in a water-wet carbonate core. Oil-displacement experiments in oil-wet carbonate core revealed that coinjection of wettability-altering surfactant and gas can recover a significant amount of oil [33% original oil in place (OOIP)] over waterflood. During foam flooding, with AOS as the foaming agent, only a weak foam was propagated in a carbonate core, irrespective of the core wettability. A blend of wettability-altering surfactant, AOS, and zwitterionic surfactant not only altered the wettability of carbonate core from oil-wet to water-wet, but also significantly increased the foam-pressure gradient in the presence of crude oil.

Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution

SPE Journal ◽  
2021 ◽  
pp. 1-24
Author(s):  
Maissa Souayeh ◽  
Rashid S. Al-Maamari ◽  
Ahmed Mansour ◽  
Mohamed Aoudia ◽  
Thomas Divers
Keyword(s):  
Contact Angle ◽  
Porous Medium ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Low Salinity ◽  
Oil Displacement

Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

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.

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.

Study of Oil Displacement Performance of Hydroxyl Sulfobetaine Surfactant

2013 ◽  
Vol 853 ◽  
pp. 223-228
Author(s):  
Pu Yue ◽  
Fan Zhang ◽  
Hui Li Fan
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Mass Fraction ◽  
Volume Fraction ◽  
Oil Field ◽  
Water Flooding ◽  
Actual Condition ◽  
Oil Reservoir ◽  
Oil Film ◽  
Oil Displacement

In this paper, new alkali-free hydroxyl sulfobetaine surfactant designed for the target oil reservoir in our laboratory was used. The interfacial tension property, emulsifying capability, peeling the oil film between surfactant/polymer binary oil-displacing system and the target crude oil and the viscosity of the system were investigated systematically. Finally, oil-displacement capacity of the binary oil-displacing system on the target reservoirs natural cores was discussed. The experimental results indicated under the actual condition of the target oil reservoir with total salinity ranging from 4694mg/L to 24270mg/L and temperature being 50°C, the surfactant/polymer binary oil-displacing system with surfactant mass fraction ranging from 0.025% to 0.2% and polymer mass fraction of 0.15% could reach ultra-low interfacial tension with the target crude oil rapidly. The surfactant/polymer binary system above mentioned could emulsified crude oil easily and the volume fraction of WinsorIII middle phase microemulsion could be up to 53.06%. It also could peel the oil film adhered to oil-wet quartz plate quickly and increase the viscoelastic of surfactant/polymer binary oil-displacing system slightly. The displacement experiments made by using natural core in the target oil field indicated that oil recovery was improved by 15% after water flooding. All these results showed that hydroxyl sulfobetaine surfactant had a good potential for flooding in EOR.

Wettability Alteration During Low-Salinity Waterflooding in a Deep Tight Carbonate Reservoirs: A Quantitative and Visual Investigation Through Spontaneous Imbibition and Zeta Potentiometric Studies

2021 ◽  
Author(s):  
N. Singh ◽  
P. H. Gopani ◽  
H. K. Sarma ◽  
F. Wu ◽  
P. S. Mattey ◽  
...  
Keyword(s):  
Contact Angle ◽  
Zeta Potential ◽  
Carbonate Reservoir ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Rock Interaction ◽  
Low Salinity ◽  
Tight Carbonate ◽  
Repulsive Forces

Abstract This study focusses on the investigation of wettability alteration behavior during low salinity waterflood (LSWF) process in a tight carbonate reservoir through Zeta potential studies in conjunction with spontaneous imbibition tests and estimation of the contact angle between the wetting fluid and the rock surface. This will help in understanding the role rock-oil-brine interactions play during an LSWF process. The classical streaming potential technique were used to determine Zeta potential. Measurements were carried out with diluted brines using different rock samples of in two states: oil-saturated and brine-saturated. The experimental results imply that the value of zeta potential becomes more negative with increasing percentage of dilution (25%, 10%, and 1%). This is attributed to electrical double-layer expansion which is caused, primarily, by the reduced ionic strength. We concluded that rock saturated with oil may give an insight on oil rock interactions while the rock saturated with brine may give insight on rock-brine interactions. The dilution of water helps increase the electrostatic repulsive forces between the two interfaces, which in turns, leads to the incremental recovery during LSWF process. This observation was also confirmed by coreflooding and wettability experiments through spontaneous imbibition tests and contact angle measurements conducted using the same oil-brine-rock systems. This is an investigative study of oil-brine-rock interaction behavior during a LSWF process that is difficult to accomplish through and during a conventional coreflooding displacement test. In addition, this study also couples the relationship between the wettability alteration and oil-brine-rock interactions during an LSWF process.

scholarly journals Impact of SO42−, Ca2+, and Mg2+ ions in Caspian Sea ion-engineered water on the rate of wettability alteration in carbonates

2020 ◽  
Vol 10 (8) ◽  
pp. 3281-3293
Author(s):  
Meruyet Bazhanova ◽  
Peyman Pourafshary
Keyword(s):  
Contact Angle ◽  
Caspian Sea ◽  
Sea Water ◽  
Research Work ◽  
Spontaneous Imbibition ◽  
Ion Concentration ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Short Period

Abstract Tuning the salinity and concentration of potential-determining ions, such as Mg2+, Ca2+, and SO42−, could alter the wettability toward a more water-wet state. The rate of alteration in carbonate rock wettability is a critical parameter to design the duration of the ion-engineered water flooding. Characteristic experiments, such as dynamic contact angle and pH measurements, ion chromatography, and spontaneous imbibition, are applied to study the rate of wettability alteration using different samples of ion-engineered water. Our study shows that the Caspian Sea water (CSW) with a salinity of 15,000 ppm is an efficient displacing fluid as it can initiate the multi-ion exchange (MIE) mechanism and alter the wettability from 86° to 35° within 2 d. The adjustment of salinity and active ion concentration makes the MIE mechanism much faster. For example, with five times diluted CSW, the same change in wettability is only achieved only within 9 h. Spiking the concentration of Ca2+ and SO42− ions is used to further shift the contact angle to 22° within 9 h. Spontaneous imbibition tests demonstrate that the rate of oil production doubles as a result of the ion-engineered brine due to the faster MIE process. The results obtained from this research work suggest that even a short period of interaction with optimized engineered water can affect the brine, oil, and carbonates interactions and change the reservoir rock initial wettability from neutral to strongly water-wet state. This allows to efficiently design engineered water flooding based on CSW in the field scale and make such projects more profitable.

Effects of Interfacial Tension Reduction and Wettability Alteration on Oil Recovery by Surfactant Imbibition

2013 ◽  
Vol 868 ◽  
pp. 664-668
Author(s):  
Zi Yuan Qi ◽  
Ye Fei Wang ◽  
Xiao Li Xu
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Spontaneous Imbibition ◽  
Surface Wettability ◽  
Wettability Alteration ◽  
Ionic Surfactants ◽  
Oil Sand ◽  
Sand Surface ◽  
Quartz Sands

Surfactant imbibition experiments were carried out with four surfactants and effects of interfacial tension and surface wettability on oil recovery were studied. A convenient imbibition process with quartz sands was used, and the experimental results suggest that anionic and non-ionic surfactants have higher oil recovery than cationic surfactant, and the sand surface wettability plays an important role in influencing oil recovery during spontaneous imbibition. Altering the wettability of oil sand surface from oil-wet to water-wet can enhance the oil recovery of imbibition process. The maximum ultimate imbibition recovery appeared in the area where both contact angle and interfacial tension were low.

Microscale Effects of Polymer on Wettability Alteration in Carbonates

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1884-1894
Author(s):  
Zuoli Li ◽  
Subhash Ayirala ◽  
Rubia Mariath ◽  
Abdulkareem AlSofi ◽  
Zhenghe Xu ◽  
...  
Keyword(s):  
Contact Angle ◽  
Crude Oil ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
High Salinity ◽  
Adhesion Force ◽  
Contact Angles ◽  
Wettability Alteration ◽  
Injection Water ◽  
Lower Contact

Summary Polymer enhances the volumetric sweep efficiency through the increased viscosity of injection water and subsequently results in enhanced oil recovery. Most of the reported experimental studies focused on only evaluating polymer viscosifying characteristics and their associated significance for achieving adequate mobility control in porous media. The microscale effects of polymer on wettability alteration in carbonates are rarely studied. In this experimental investigation, the wettability of carbonates in the presence of polymer was measured using contact angle tests. In addition, the adhesion force between carbonate and crude oil droplets in polymer solutions was determined using a custom-designed integrated thin-film drainage apparatus equipped with a bimorph sensor. The liberation kinetics of crude oil from carbonate surfaces were also measured by an optical microscope-based liberation cell to understand the wettability alteration effects on oil recovery. All the experiments, except the adhesion force, which was measured at room temperature due to the restriction of bimorph sensor, were conducted at both ambient and elevated temperatures (70°C) using a sulfonated polyacrylamide polymer (SPAM) (at 500 and 700 ppm) in high-salinity injection water. Deionized (DI) water was used as a baseline to provide a representative comparison with the high-salinity brine. The contact angles of crude oil droplets on a carbonate surface were highest in DI water and decreased in brine. The addition of polymer decreased the contact angle further, with higher concentrations of polymer resulting in a lower contact angle. The adhesion force between crude oil and carbonate showed good agreement with contact angle data, and the oil adhesion was smallest on the carbonate surface in the presence of polymer. The crude oil liberation from the carbonate surface by flooding with brine and polymer was found to be more efficient at elevated temperature than at ambient temperature, consistent with lower contact angles measured in these aqueous solutions at high temperature. The equilibrium oil liberation degree with polymer solutions increased by more than two times when the temperature was increased from 23 to 70°C. The higher liberation degree obtained with polymer solutions also correlated well with the lowest adhesion force measured between crude oil and carbonate in the presence of polymer. These consistent results obtained from different experimental techniques indicated that the oil recovery improvements observed with polymer in dynamic liberation tests are not only related to the increase in water viscosity but are also due to favorable changes in wettability as inferred from both contact angle and adhesion force measurements. This experimental study, for the first time, characterized the microscale effects of polymer on wettability alteration and crude oil liberation in carbonates. The favorable effect of polymer on wettability alteration in carbonates revealed from this study has not been reported in the literature, and it can become a novel addition to the existing knowledge.

scholarly journals Role of divalent ions, temperature, and crude oil during water injection into dolomitic carbonate oil reservoirs

2019 ◽  
Vol 74 ◽  
pp. 36 ◽  
Author(s):  
Mohammad Fattahi Mehraban ◽  
Shahab Ayatollahi ◽  
Mohammad Sharifi
Keyword(s):  
Contact Angle ◽  
Crude Oil ◽  
Oil Recovery ◽  
Elevated Temperatures ◽  
Angle Measurement ◽  
Wettability Alteration ◽  
Effect Of Temperature ◽  
Surface Charges ◽  
Potential Measurement ◽  
Asphaltene Content

Although wettability alteration has been shown to be the main control mechanism of Low Salinity and Smart Water (LS-SmW) injection, our understanding of the phenomena resulting in wettability changes still remains incomplete. In this study, more attention is given to direct measurement of wettability through contact angle measurement at ambient and elevated temperatures (28 °C and 90 °C) during LS-SmW injection to identify trends in wettability alteration. Zeta potential measurement is utilized as an indirect technique for wettability assessment in rock/brine and oil/brine interfaces in order to validate the contact angle measurements. The results presented here bring a new understanding to the effect of temperature and different ions on the wettability state of dolomite particles during an enhanced oil recovery process. Our observations show that increasing temperature from 28 °C to 90 °C reduces the contact angle of oil droplets from 140 to 41 degrees when Seawater (SW) is injected. Besides, changing crude oil from crude-A (low asphaltene content) to crude-B (high asphaltene content) contributes to more negative surface charges at the oil/brine interface. The results suggest that the sulphate ion (SO42-) is the most effective ion for altering dolomite surface properties, leading to less oil wetness. Our study also shows that wettability alteration at ambient and elevated temperatures during LS-SmW injection can be explained by Electrical Double Layer (EDL) theory.

Novel Application of Cationic Surfactants for Foams With Wettability Alteration in Oil-Wet Low-Permeability Carbonate Rocks

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2218-2231 ◽  
Author(s):  
Pinaki Ghosh ◽  
Kishore K. Mohanty
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Foam Stability ◽  
Wettability Alteration ◽  
Low Permeability ◽  
Zwitterionic Surfactants ◽  
Oil Displacement ◽  
Tertiary Oil Recovery ◽  
Carbonate Cores ◽  
Displacement Experiments

Summary Carbonate rocks are typically heterogeneous at many scales, leading to low waterflood recoveries. Polymers and gels cannot be injected into nonfractured low-permeability carbonates (k < 10 md) because pore throats are smaller than the polymers. Foams have the potential to improve both oil-displacement efficiency and sweep efficiency in such carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several cationic-foam formulations that combine wettability alteration and foaming in low-permeability oil-wet carbonate cores. Contact-angle experiments were performed on initially oil-wet media to evaluate the wettability-altering capabilities of the surfactant formulations. Static foam-stability tests were conducted to evaluate their foaming performance in bulk; foam-flow experiments (without crude oil) were performed in porous media to estimate the foam strength. Finally, oil-displacement experiments were performed with a crude oil after a secondary gasflood. Two different injection strategies were studied in this work: surfactant slug followed by gas injection and coinjection of surfactant with gas at a constant foam quality. Systematic study of oil-displacement experiments in porous media showed the importance of wettability alteration in increasing tertiary oil recovery for oil-wet media. Several blends of cationic, nonionic, and zwitterionic surfactants were used in the experiments. In-house-developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed an increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil-displacement experiments in oil-wet carbonate cores revealed that tertiary oil recovery with injection of a wettability-altering surfactant and foam can recover a significant amount of oil [approximately 25 to 52% original oil in place (OOIP)] over the secondary gasflood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low-permeability carbonate cores.

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