scholarly journals Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Polymers ◽  
2020 ◽  
Vol 12 (10) ◽  
pp. 2241
Author(s):  
Vladislav Arekhov ◽  
Rafael E. Hincapie ◽  
Torsten Clemens ◽  
Muhammad Tahir
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Chemical Agent ◽  
Aging Effects ◽  
Divalent Ions ◽  
Total Acid

The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

2021 ◽  
pp. 1-18
Author(s):  
Takaaki Uetani ◽  
Hiromi Kaido ◽  
Hideharu Yonebayashi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Oil Composition ◽  
Total Acid ◽  
Low Salinity ◽  
Total Acid Number

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

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.

Dynamics of Low-Interfacial-Tension Imbibition in Oil-Wet Carbonates

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1092-1107 ◽  
Author(s):  
M.. Tagavifar ◽  
M.. Balhoff ◽  
K.. Mohanty ◽  
G. A. Pope
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Flow Behavior ◽  
Contact Angles ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Surface Phenomenon ◽  
Rock Surface ◽  
The Core ◽  
Aspect Ratios

Summary Surfactants induce spontaneous imbibition of water into oil-wet porous media by wettability alteration and interfacial-tension (IFT) reduction. Although the dependence of imbibition on wettability alteration is well-understood, the role of IFT is not as clear. This is partly because, at low IFT values, most water/oil/amphiphile(s) mixtures form emulsions and/or microemulsions, suggesting that the imbibition is accompanied by a phase change, which has been neglected or incorrectly accounted for in previous studies. In this paper, spontaneous displacement of oil from oil-wet porous media by microemulsion-forming surfactants is investigated through simulations and the results are compared with existing experimental data for low-permeability cores with different aspect ratios and permeabilities. Microemulsion viscosity and oil contact angles, with and without surfactant, were measured to better initialize and constrain the simulation model. Results show that with such processes, the imbibition rate and the oil recovery scale differently with core dimensions. Specifically, the rate of imbibition is faster in cores with larger diameter and height, but the recovery factor is smaller when the core aspect ratio deviates considerably from unity. With regard to the mechanism of water uptake, our results suggest, for the first time, that (i) microemulsion formation (i.e., fluid/fluid interface phenomenon) is fast and favored over the wettability alteration (i.e., rock-surface phenomenon) in short times; (ii) a complete wettability transition from an oil-wet to a mixed microemulsion-wet and surfactant-wet state always occurs at ultralow IFT; (iii) wettability alteration causes a more uniform imbibition profile along the core but creates a more diffused imbibition front; and (iv) total emulsification is a strong assumption and fails to describe the dynamics and the scaling of imbibition. Wettability alteration affects the imbibition dynamics locally by changing the composition path, and at a distance by changing the flow behavior. Simulations predict that even though water is not initially present, it forms inside the core. The implications of these results for optimizing the design of low-IFT imbibition are discussed.

A Model for Wettability Alteration in Fractured Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1261-1275 ◽  
Author(s):  
Pål Østebø Andersen ◽  
Steinar Evje ◽  
Hans Kleppe ◽  
Svein Magne Skjæveland
Keyword(s):  
Oil Recovery ◽  
Enhanced Recovery ◽  
Fractured Reservoirs ◽  
Ionic Composition ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Numerical Code ◽  
Significant Feature ◽  
Rock Surface ◽  
Single Fracture

Summary We present a mathematical model for wettability alteration (WA) in fractured reservoirs. Flow in the reservoir is modeled by looking at a single fracture surrounded by matrix on both sides. Water is injected into the formation with a chemical component that enters the matrix and adsorbs onto the rock surface. These changes of the mineral surface are assumed to alter the wettability toward a more water-wet state, which leads to enhanced recovery by spontaneous imbibition. This can be viewed as a representation of “smart water” injection in which the ionic composition of injection brine affects recovery. The WA is described by shifting curves for relative permeability and capillary pressure from curves representing preferentially oil-wet (POW) conditions toward curves representing more-water-wet conditions. The numerical code was successfully compared with ECLIPSE for the specific case in which a fixed wetting state is assumed. Also, the relevance of the WA model was illustrated by modeling a spontaneous-imbibition experiment in which only a modification of the brine composition led to a change in oil recovery. The model can predict sensitivity to matrix properties such as wettability, permeability, and fracture spacing and to external parameters such as schedule of brine compositions and injection rate. Our model illustrates that one cannot use conventional reservoir modeling to capture accurately the behavior we observe. The rate of recovery and the level of recovery have a strong dependency on the component chemistry and its distribution. A significant feature of gradual WA by injecting a component is that the rate of fluid transfer is maintained between matrix and fracture. The resulting recovery profile after water breakthrough can behave close to linear as opposed to the square-root-of-time profile that is observed when the wetting state is fixed (Rangel-German and Kovscek 2002). The water will typically break through early as dictated by the initial POW state, but a higher final recovery will be obtained because higher saturations can imbibe. Improved understanding of the coupling between WA controlled by water/rock chemistry and fracture/matrix flow is highly relevant for gaining more insight into recovery from naturally fractured reservoirs.

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.

scholarly journals Wettability Changes Due to Nanomaterials and Alkali—A Proposed Formulation for EOR

Nanomaterials ◽  
2021 ◽  
Vol 11 (9) ◽  
pp. 2351
Author(s):  
Samhar Saleh ◽  
Elisabeth Neubauer ◽  
Ante Borovina ◽  
Rafael E. Hincapie ◽  
Torsten Clemens ◽  
...  
Keyword(s):  
Diffusion Coefficient ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Bond Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Total Acid ◽  
Silica Nanomaterials ◽  
Alkaline Agent ◽  
Surface Modified

We investigated the usage of two silica nanomaterials (surface-modified) and alkali in enhanced oil recovery through Amott spontaneous imbibition tests, interfacial tension (IFT) measurements, and phase behavior. We evaluated the wettability alteration induced by the synergy between nanomaterials and alkali. Moreover, numerical analysis of the results was carried out using inverse Bond number and capillary diffusion coefficient. Evaluations included the use of Berea and Keuper outcrop material, crude oil with different total acid numbers (TAN), and Na2CO3 as alkaline agent. Data showed that nanomaterials can reduce the IFT, with surface charge playing an important role in this process. In synergy with alkali, the use of nanomaterials led to low-stable IFT values. This effect was also seen in the phase behavior tests, where brine/oil systems with lower IFT exhibited better emulsification. Nanomaterials’ contribution to the phase behavior was mainly the stabilization of the emulsion middle phase. The influence of TAN number on the IFT and phase behavior was prominent especially when combined with alkali. Amott spontaneous imbibition resulted in additional oil recovery ranging from 4% to 50% above the baseline, which was confirmed by inverse Bond number analysis. High recoveries were achieved using alkali and nanomaterials; these values were attributed to wettability alteration that accelerated the imbibition kinetics as seen in capillary diffusion coefficient analysis.

scholarly journals Application of ion-engineered Persian Gulf seawater in EOR: effects of different ions on interfacial tension, contact angle, zeta potential, and oil recovery

2021 ◽  
Author(s):  
Amir Hossein Saeedi Dehaghani ◽  
Seyed Masoud Ghalamizade Elyaderani
Keyword(s):  
Contact Angle ◽  
Zeta Potential ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Persian Gulf ◽  
Rock Surface ◽  
Divalent Ions ◽  
Smart Water ◽  
Wet Condition ◽  
The Persian Gulf

AbstractIn this study, we initially performed interfacial tension (IFT) tests to investigate the potential of using the Persian Gulf seawater (PGSW) as smart water with different concentrations of NaCl, KCl, MgCl2, CaCl2, and Na2SO4. Next, for each salt, at the concentration where IFT was minimum, we conducted contact angle, zeta potential, and micromodel flooding tests. The results showed that IFT is minimized if NaCl or KCl is removed from PGSW; thus, for solutions lacking NaCl and KCl, the IFT values were obtained at 26.29 and 26.56 mN/m, respectively. Conversely, in the case of divalent ions, minimum IFT occurred when the concentration of MgCl2, CaCl2, and Na2SO4 in PGSW increased. Specifically, a threefold rise in the concentration of Na2SO4 further reduced IFT as compared to optimal concentrations of MgCl2 or CaCl2. It should be mentioned that eliminating NaCl from PGSW resulted in the lowest IFT value compared to adding or removing other ions. Whereas the removal of NaCl caused the contact angle to decrease from 91.0° to 67.8° relative to PGSW and changed surface wettability to weakly water-wet, eliminating KCl did not considerably change the contact angle, such that it only led to a nine-degree reduction in this angle relative to PGSW and left wettability in the same neutral-wet condition. At optimal concentrations of MgCl2, CaCl2, and Na2SO4, only an increase in Na2SO4 concentration in PGSW could change wettability from neutral-wet to weakly water-wet. For solutions with optimal concentrations, the removal of NaCl or KCl caused the rock surface to have slightly higher negative charges, and increasing the concentration of divalent ions led to a small reduction in the negative charge of the surface. The results of micromodel flooding indicated that NaCl-free PGSW could raise oil recovery by 10.12% relative to PGSW. Furthermore, when the Na2SO4 concentration in PGSW was tripled, the oil recovery increased by 7.34% compared to PGSW. Accordingly, depending on the conditions, it is possible to use PGSW so as to enhance the efficiency of oil recovery by removing NaCl or by increasing the concentration of Na2SO4 three times.

Wettability Alteration of Dolomite Rock Using Nanofluids for Enhanced Oil Recovery

2016 ◽  
Vol 864 ◽  
pp. 194-198 ◽  
Author(s):  
Mohd Shahrizan Moslan ◽  
Wan Rosli Wan Sulaiman ◽  
Abdul Razak Ismail ◽  
Mohd Zaidi Jaafar ◽  
Issham Ismail
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Ion Pairs ◽  
Adsorption Rate ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Wet Condition ◽  
The Impact

Wettability alteration of rock by surfactant has been considered as feasible method for recovery of oil reservoirs by modifying the wettability of rock surface from oil-wet to water-wet condition. The impact of surfactant can be enhanced by adding nanoparticles. Cationic surfactant performed well in carbonate rock by forming ion pairs between cationic head and acidic component of the crude. Meanwhile, nanoparticles will form continuous wedge film between the liquid and solid surface. In this paper, Al2O3 and ZrO2 nanoparticles were used as enhanced oil recovery (EOR) agents. The impact of these two nanoparticles on contact angle and interfacial tension was studied. Besides that, adsorption Cetyltrimethylammonium Bromide (CTAB) surfactant on rock surface was also investigated. The results show a significant change in water-oil contact angle after application of surfactant and nanoparticles. Initial water-oil contact angle for 6 dolomites demonstrate oil-wet condition. Then, the dolomites were submerged in prepared solution for 48 hours. The result shows that, dolomites 2, 5 and 6 changes drastically to more water-wet condition with contact angle 56°, 40° and 47° respectively. For surfactant adsorption, the adsorption is very fast at the beginning. The adsorption rate after 5 minutes was 50 mg/g and after 60 minutes the adsorption rate was 310 mg/g. The adsorption rate slowed down after 60 minutes and after 180 minutes the adsorption rate was 315 mg/g in which the rate of adsorption achieve equilibrium. Nanoparticles retention test and Zeta potential shows that Al2O3 is more stable than ZrO2. The results for interfacial tension (IFT) also show a significant reduction. The IFT value reduces from 8.46 mN/m to 1.65 mN/m and 1.85 mN/m after the application of Al2O3 and ZrO2 nanofluids respectively

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 Wettability alteration and oil recovery by spontaneous imbibition of smart water and surfactants into carbonates

2020 ◽  
Vol 17 (3) ◽  
pp. 712-721 ◽  
Author(s):  
Saeb Ahmadi ◽  
Mostafa Hosseini ◽  
Ebrahim Tangestani ◽  
Seyyed Ebrahim Mousavi ◽  
Mohammad Niazi
Keyword(s):  
Contact Angle ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Smart Water ◽  
Fractured Carbonate ◽  
Enhance Oil Recovery

AbstractNaturally fractured carbonate reservoirs have very low oil recovery efficiency owing to their wettability and tightness of matrix. However, smart water can enhance oil recovery by changing the wettability of the carbonate rock surface from oil-wet to water-wet, and the addition of surfactants can also change surface wettability. In the present study, the effects of a solution of modified seawater with some surfactants, namely C12TAB, SDS, and TritonX-100 (TX-100), on the wettability of carbonate rock were investigated through contact angle measurements. Oil recovery was studied using spontaneous imbibition tests at 25, 70, and 90 °C, followed by thermal gravity analysis to measure the amount of adsorbed material on the carbonate surface. The results indicated that Ca2+, Mg2+, and SO42− ions may alter the carbonate rock wettability from oil-wet to water-wet, with further water wettability obtained at higher concentrations of the ions in modified seawater. Removal of NaCl from the imbibing fluid resulted in a reduced contact angle and significantly enhanced oil recovery. Low oil recoveries were obtained with modified seawater at 25 and 70 °C, but once the temperature was increased to 90 °C, the oil recovery in the spontaneous imbibition experiment increased dramatically. Application of smart water with C12TAB surfactant at 0.1 wt% changed the contact angle from 161° to 52° and enhanced oil recovery to 72%, while the presence of the anionic surfactant SDS at 0.1 wt% in the smart water increased oil recovery to 64.5%. The TGA analysis results indicated that the adsorbed materials on the carbonate surface were minimal for the solution containing seawater with C12TAB at 0.1 wt% (SW + CTAB (0.1 wt%)). Based on the experimental results, a mechanism was proposed for wettability alteration of carbonate rocks using smart water with SDS and C12TAB surfactants.

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