A New Dynamic Wettability-Alteration Model for Oil-Wet Cores During Surfactant-Solution Imbibition

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 818-828 ◽  
Author(s):  
M. Hosein Kalaei ◽  
Don W. Green ◽  
G. Paul Willhite
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
History Matching ◽  
Mechanistic Model ◽  
Surfactant Solution ◽  
Experimental Tests ◽  
Quantitative Agreement ◽  
Wettability Alteration ◽  
Porous Rock ◽  
Surfactant Solutions

Summary Wettability modification of solid rocks with surfactants is an important process and has the potential to recover oil from reservoirs. When wettability is altered by use of surfactant solutions, capillary pressure, relative permeabilities, and residual oil saturations change wherever the porous rock is contacted by the surfactant. In this study, a mechanistic model is described in which wettability alteration is simulated by a new empirical correlation of the contact angle with surfactant concentration developed from experimental data. This model was tested against results from experimental tests in which oil was displaced from oil-wet cores by imbibition of surfactant solutions. Quantitative agreement between the simulation results of oil displacement and experimental data from the literature was obtained. Simulation of the imbibition of surfactant solution in laboratory-scale cores with the new model demonstrated that wettability alteration is a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. In these simulations, the gravity force was the primary cause of the surfactant-solution invasion of the core that changed the rock wettability toward a less oil-wet state.

A Mechanistic Model for Wettability Alteration by Chemically Tuned Waterflooding in Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 767-783 ◽  
Author(s):  
C.. Qiao ◽  
L.. Li ◽  
R.T.. T. Johns ◽  
J.. Xu
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Reactive Transport ◽  
Mechanistic Model ◽  
Contact Angles ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Physical Parameters ◽  
Minor Effect

Summary Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to more-water-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidic-oil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2+, Mg2+) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2+ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

Geochemical Modeling of Hybrid Surfactant and Engineered Water Injections in Carbonate Reservoirs under Harsh Conditions

SPE Journal ◽  
2021 ◽  
pp. 1-25
Author(s):  
Ahmed Adila ◽  
Emad W. Al-Shalabi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Ion Concentration ◽  
Wettability Alteration ◽  
Surfactant Flooding ◽  
Exchange Reactions ◽  
Concentration Data ◽  
Data Set ◽  
Hybrid Surfactant ◽  
Harsh Conditions

Summary Engineered water injection (EWI) has gained popularity as an effective technique for enhancing oil recovery. Surfactant flooding is also a well-established chemical enhanced-oil-recovery (EOR) technique in the petroleum industry. The hybrid surfactant flooding/EWI (surfactant/EWI) technique has been studied experimentally and showed promising results. However, there are very limited numerical applications on the hybrid surfactant/EWI technique in carbonates in the literature. Also, the studies applied under harsh conditions of high temperature and high salinity are even fewer. In this study, a numerical-simulation model is developed and used to investigate the hybrid effect of surfactant/EWI in carbonates under harsh conditions. This developed model was validated by history matching a recently conducted surfactant coreflood in the secondary mode of injection. Oil recovery, pressure drop, and surfactant-concentration data were used. The surfactant-flooding model was then coupled with a geochemical model that captures different reactions involved during EWI. The geochemical reactions considered include aqueous, dissolution/precipitation, and ion-exchange reactions. The proposed model has been further validated by history matching another experimental data set. Furthermore, different simulation scenarios were considered, including waterflooding, surfactant flooding, EWI, and the hybrid surfactant/EWI technique. For the case of EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial-tension (IFT) reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that for the hybrid surfactant/EWI, wettability alteration is considered as the controlling mechanism where surfactant boosts oil-recovery rate through increasing oil relative permeability while EWI reduces residual oil. Moreover, the simulation runs showed that the hybrid surfactant/EWI is a promising technique for enhancing oil recovery from carbonates under harsh conditions. Also, hybrid surfactant/EWI results in a more water-wetting rock condition compared with that of EWI alone, which leads to lower injectivity, and hence, lower rate of propagation for ion-concentration waves. The hybrid surfactant/EWI outperformed other injection techniques followed by EWI, then surfactant flooding, and finally waterflooding. This work gives more insight into the application of hybrid surfactant/EWI on enhancing oil recovery from carbonates. The novelty is further highlighted through applying the hybrid surfactant/EWI technique under harsh conditions. In addition, the findings of this study can help in better understanding the mechanism behind enhancing oil recovery using the hybrid surfactant/EWI technique and the important parameters needed to model its effect on oil recovery.

Displacement Efficiency for Low-Salinity Polymer Flooding Including Wettability Alteration

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 417-430 ◽  
Author(s):  
Saeid Khorsandi ◽  
Changhe Qiao ◽  
Russell T. Johns
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Analytical Solutions ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Wettability Alteration ◽  
Displacement Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Summary Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date. This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator. The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.

Geochemical Modeling of Hybrid Surfactant and Engineered Water Injections in Carbonate Reservoirs under Harsh Conditions

2021 ◽  
Author(s):  
Ahmed Adila ◽  
Emad W. Al-Shalabi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Water Injection ◽  
Petroleum Industry ◽  
Wettability Alteration ◽  
Surfactant Flooding ◽  
Exchange Reactions ◽  
Concentration Data ◽  
Hybrid Surfactant ◽  
Harsh Conditions

Abstract Engineered water injection (EWI) has gained popularity as an effective technique for enhancing oil recovery. Surfactant flooding is also a well-established and commercially-available technique in the petroleum industry. In this study, a numerical simulation model is developed and used to investigate the hybrid effect of surfactant-EWI in carbonates. This developed model was validated by history-matching a recently conducted surfactant coreflood in the secondary mode of injection. Oil recovery, pressure drop, and surfactant concentration data were utilized. The surfactant flooding model was then coupled with a geochemical model that captures different reactions during engineered water injection. The geochemical reactions considered include: aqueous, dissolution/precipitation, and ion- exchange reactions. Also, different simulation scenarios were considered including waterflooding, surfactant flooding, engineered water injection, and the hybrid surfactant-EWI technique. For the case of EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial tension reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that for the hybrid surfactant-EWI, wettability alteration is considered as the controlling mechanism where surfactant boosts oil recovery rate through increasing oil relative permeability while EWI reduces residual oil. Moreover, the simulation runs showed that the hybrid surfactant-EWI is a promising technique for enhancing oil recovery from carbonates under harsh conditions. The hybrid surfactant-EWI outperformed other injection techniques followed by EWI, then surfactant flooding, and least waterflooding. This work gives more insight into the application of hybrid surfactant-EWI on enhancing oil recovery from carbonates.

Surfactant-Aided Low-Salinity Waterflooding for Low-Temperature Carbonate Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Yue Shi ◽  
Chammi Miller ◽  
Kishore Mohanty
Keyword(s):  
Low Temperature ◽  
Oil Recovery ◽  
Anionic Surfactants ◽  
Surfactant Solution ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Original Oil In Place

Summary Carbonate reservoirs tend to be oil-wet/mixed-wet and heterogeneous because of mineralogy and diagenesis. The objective of this study is to improve oil recovery in low-temperature dolomite reservoirs using low-salinity and surfactant-aided spontaneous imbibition. The low-salinity brine composition was optimized using ζ-potential measurements, contact-angle (CA) experiments, and a novel wettability-alteration measure. Significant wettability alteration was observed on dolomite rocks at a salinity of 2,500 ppm. We evaluated 37 surfactants by performing CA, interfacial-tension (IFT), and spontaneous-imbibition experiments. Three (quaternary ammonium) cationic and one (sulfonate) anionic surfactants showed significant wettability alteration and produced 43–63% of original oil in place (OOIP) by spontaneous imbibition. At a low temperature (35°C), oil recovery by low-salinity effect is small compared with that by wettability-altering surfactants. Coreflood tests were performed with a selected low-salinity cationic surfactant solution. A novel coreflood was proposed that modeled heterogeneity and dynamic imbibition into low-permeability regions. The results of the “heterogeneous” coreflood were consistent with that of spontaneous-imbibition tests. These experiments demonstrated that a combination of low-salinity brine and surfactants can make originally oil-wet dolomite rocks more water-wet and improve oil recovery from regions bypassed by waterflood at a low temperature of 35°C.

scholarly journals Surfactant screening to generate strong foam with formation water and crude oil

2021 ◽  
Author(s):  
Muhammad Khan Memon ◽  
Khaled Abdalla Elraies ◽  
Mohammed Idrees Ali Al-Mossawy
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Surfactant Concentration ◽  
Surfactant Solution ◽  
Formation Water ◽  
Systematic Screening ◽  
Stable Foam ◽  
Surfactant Solutions ◽  
Foam Generation ◽  
Foam Properties

AbstractMost of the available commercial surfactants precipitate due to the hardness of formation water. The study of surfactant generated foam and its stability is very complex due to its multifaceted pattern and common physicochemical properties. This research involved the study of foam generation by using the blended surfactants and their evaluation in terms of enhanced oil recovery (EOR). The objective of this study is to systematic screening of surfactants based on their capability to produce stable foam in the presence of two different categories of crude oil. Surfactant types such as non-ionic, anionic and amphoteric were selected for the experimental study. The foam was generated with crude oil, and the synthetic brine water of 34,107 ppm used as formation water. Surfactant concentration with the both types of crude oil, foam decay, liquid drainage and foam longevity was investigated by measuring the generated foam volume above the liquid level. The surfactant with concentration of 0.6wt%AOSC14-16, 1.2wt%AOSC14-16, 0.6wt%AOSC14-16 + 0.6wt%TX100 and 0.6wt%AOSC14-16 + 0.6wt%LMDO resulted in the maximum foam longevity with formation water and two categories of crude oil. The 50% liquid drainage and foam decay of surfactant solutions with concentration of 0.6wt%AOSC14-16 + 0.6wt%LMDO and 0.6wt%AOSC14-16 + 0.6wt%TX100 were noted with the maximum time. The findings of this research demonstrated that the generated foam and its longevity is dependent on the type of surfactant either individual or blended with their concentration. The blend of surfactant solution combines excellent foam properties.

Pore Scale Study of the Effects of Wettability Alteration on Enhanced Oil Recovery

2021 ◽  
Author(s):  
Weipeng Yang ◽  
Jun Lu
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Surfactant Solution ◽  
Recovery Process ◽  
Wettability Alteration ◽  
Immiscible Displacement ◽  
Microfluidic Chips ◽  
Pore Scale ◽  
Low Velocity ◽  
Different Characteristics

Abstract Drainage displacement at unfavorable viscosity ratios is often encountered in oil recovery process, which significantly limits the oil recovery. Surfactants have been extensively used as wettability modifier to improve the hydrocarbon recovery from rock matrix by imbibition, but little attention has been paid to the use of surfactant-aided wettability alteration to suppress fingering during displacement. In this study, we investigate the surfactant-aided immiscible displacement in oil-wet microfluidic chips. We find that the change of advancing contact angle by surfactant is velocity dependent and stable displacement can be achieved at low velocity when surfactant solution is used at the injection fluid. In comparison, fingering occurs at all capillary numbers for water injection, resulting in low oil recovery. Besides, the generation of oil ganglion during waterflooding and surfactant flooding exhibits completely different characteristics. Our study reveals the pore-scale mechanism of surfactant-aided wettability on the immiscible displacement, which is important for highly efficient oil recovery.

In-Situ Visualization of Multidimensional Imbibition in Dual-Porosity Carbonates

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1631-1642 ◽  
Author(s):  
Amar J. Alshehri ◽  
Anthony R. Kovscek
Keyword(s):  
Oil Recovery ◽  
Experimental Results ◽  
Wettability Alteration ◽  
X Ray ◽  
Surfactant Solutions ◽  
Phase Saturation ◽  
Gravity Effects ◽  
The Matrix ◽  
Ultralow Ift

Summary Oil recovery by waterflood is usually small in fractured carbonates because of selective channeling of injected water through fractures toward producers, leaving much of the oil trapped in the matrix. One option to mitigate the low recovery is to reduce fracture uptake by increasing the viscosity of the injected fluids by use of polymers or foams. Another option, that is the objective of this work, is to inject surfactant solutions to reduce capillary effects responsible for trapping oil and allow gravity to segregate oil by buoyancy. Analysis of gravity and capillary forces suggests that such segregation is achievable in the laboratory, provided that cores are moderately long and oriented vertically. Besides investigating the role of gravity on oil recovery, the effect of surfactant-flood mode (secondary-flood mode and tertiary-flood mode) on the ultimate recovery (UR) was also investigated. To investigate the predictions of this analysis, coreflood experiments were conducted by use of carbonate cores and monitored by an X-ray computed-tomography (CT) scanner featuring true vertical positioning to quantify fluid saturation history in situ. Novel aspects of this work include cores that are oriented both horizontally and vertically to maximize gravitational effects as well as a special core holder that mimics aspects of fractured systems by use of the whole core. This paper discusses the contrast in experimental results in vertical and horizontal orientation with and without surfactant. To study gravity effects, surfactant reduced interfacial tension (IFT) from 40 to 3 mN/m. For this mode of recovery, ultralow IFT is not preferred because some capillary action is needed to aid injectant transport into the matrix. The vertical experiment showed that gravity has the potential of improving oil recovery at low IFT. Another surfactant was used to study the flood-mode effect; this surfactant reduced IFT from 40 to 0.001 mN/m (ultralow IFT). In this study, two experiments were conducted: a tertiary-surfactant-flood experiment and a secondary-surfactant-flood experiment. The secondary-flood experiment showed an improvement in recovery with the early implementation of the surfactant flood relative to the tertiary-flood experiment. This work highlights the importance of gravity at low IFT in terms of mobilizing trapped oil and also the effect of flood mode on UR. Moreover, this work emphasizes the use of surfactant solutions as a method of enhancing oil recovery in fractured resources not necessarily because of wettability alteration but mainly because of gravity effects. Experimental results are presented primarily as 1D and 3D reconstructions of in-situ oil- and water-phase saturation obtained by use of X-ray CT.

scholarly journals Review on enhanced oil recovery by nanofluids

2018 ◽  
Vol 73 ◽  
pp. 37 ◽  
Author(s):  
Kewen Li ◽  
Dan Wang ◽  
Shanshan Jiang
Keyword(s):  
Experimental Data ◽  
Aqueous Solution ◽  
Surface Tension ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Oil Viscosity ◽  
Interfacial Surface ◽  
Lack Of Control ◽  
Water Based ◽  
Enhance Oil Recovery

The addition of nanoparticles into water based fluids (nanofluid) with or without other chemicals to Enhance Oil Recovery (EOR) has recently received intensive interest. Many papers have been published in this area and several EOR mechanisms have been proposed. The main EOR mechanisms include wettability alteration, reduction in InterFacial surface Tension (IFT), increase in the viscosity of aqueous solution, decrease in oil viscosity, and log-jamming. Some of these mechanisms may be associated with the change in disjoining pressure because of the addition of the nanoparticles. The experimental data and results reported by different researchers, however, are not all consistent and some even conflict with others. Many papers published in recent years have been reviewed and the associated experimental data have been analyzed in this paper in order to clarify the mechanisms of EOR by nanofluids. Wettability alteration may be one of the most accepted mechanisms for nanofluid EOR while reduction in IFT and other mechanisms have not been fully proven. The main reason for the inconsistency among the experimental data might be lack of control experiments in which the effect of nanoparticles on oil recovery would be singled out.

scholarly journals Feasibility Investigation of A Novel Natural Surfactant Extracted from Eucalyptus Leaves for Enhanced Oil Recovery of Carbonates: Experimental Study

2018 ◽  
Vol 1 (1) ◽  
Keyword(s):  
Oil Recovery ◽  
Pore Space ◽  
Low Cost ◽  
Surfactant Solution ◽  
Wettability Alteration ◽  
Chemical Flooding ◽  
Reservoir Rocks ◽  
Eucalyptus Leaves ◽  
Natural Surfactant ◽  
Oil Water

After primary and secondary oil production from carbonate reservoirs, approximately 60% oil-in-place remains in the pore space of reservoir rocks. Chemical flooding is one of the promising ways to produce the remained oil. Nowadays, surfactant flooding is a low-cost and a common method generally used to improve oil recovery due to the oil-water Interfacial Tension (IFT) reduction and alteration of the rock wettability to water-wet state, leading to decrease the capillary number. In this study, a novel leaf-derived non-ionic natural surfactant, named Eucalyptus is introduced and the capability of this natural surfactant for IFT reduction and wettability alteration is analyzed. Accordingly, the natural surfactant was derived from Eucalyptus leaves and the effect of natural surfactant solution on the Oil-water IFT and carbonate rock wettability alteration was investigated. The results demonstrated that the addressed natural surfactant significantly reduced IFT value from 35.2 mN/m to 10.5 mN/m (at CMC of 3.5 wt. %) and the contact angle value from 140.6° to 60.2°. As a result, Compared to conventional chemical surfactants, the Eucalyptus natural surfactant had an excellent surface chemical activity and confirmed its performance by laboratory experiments which could be used for EOR applications.

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