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.

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.

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.

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.

Study on the Mechanism of Enhancing Oil Recovery by Molecular Film Displacement

2011 ◽  
Vol 236-238 ◽  
pp. 2135-2141
Author(s):  
Qi Cheng Liu ◽  
Yong Jian Liu
Keyword(s):  
Oil Recovery ◽  
Electrostatic Interaction ◽  
Ultrathin Films ◽  
Water Solution ◽  
Wettability Alteration ◽  
Nanometer Scale ◽  
Rock Surface ◽  
Capillary Imbibition ◽  
Molecular Film ◽  
Polymer Surfactant

Molecular film displacement is a new nanofilm EOR technique. A large number of experiments show that the mechanism of molecular film displacement is different from conventional chemical displacement (polymer, surfactant, alkali and ASP displacement etc). With water solution acting as transfer medium, molecules of the filming agent develop the force to form films through electrostatic interaction, with efficient molecules deposited on the negatively charged rock surface to form ultrathin films at nanometer scale. This change the properties of reservoir surface and the interaction condition with crude oil, making the oil easily be displaced as the pores swept by the injected fluid. Thus oil recovery is enhanced. The mechanism of molecular filming agent mainly includes absorption, wettability alteration, diffusion and capillary imbibition etc.

Labortory and Pilot Tests of Enhanced Oil Recovery through Wettability Alteration by Diluted Microemulsions

2021 ◽  
Author(s):  
Xurong Zhao ◽  
Tianbo Liang ◽  
Jingge Zan ◽  
Mengchuan Zhang ◽  
Fujian Zhou ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Core Flooding ◽  
Fracturing Fluid ◽  
Invasion Front ◽  
Wetting Ability ◽  
On Line ◽  
Wet Rocks

Abstract Replacing oil from small pores of tight oil-wet rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, the liquid nanofluid has less adsorption loss during transport in the porous media, and can efficiently alter the rock wettability; meanwhile, it can also maintain a certain oil-water interfacial tension driving the water imbibition. In the previous study, the main properties of a Nonionic nanofluid-diluted microemulsion (DME) were evaluated, and the dispersion coefficient and adsorption rate of DME in tight rock under different conditions were quantified. In this study, to more intuitively show the change of wettability of DME to oil-wet rocks in the process of core flooding experiments and the changes of the water invasion front, CT is used to carry out on-line core flooding experiments, scan and calculate the water saturation in time, and compare it with the pressure drop in this process. Besides, the heterogeneity of rock samples is quantified in this paper. The results show that when the DME is used as the fracturing fluid additive, fingering of the water phase is observed at the beginning of the invasion; compared with brine, the fracturing fluid with DME has deeper invasion depth at the same time; the water invasion front gradually becomes uniform when the DME alters the rock wettability and triggers the imbibition; for tight rocks, DME can enter deeper pores and replace more oil because of its dominance. Finally, the selected nanofluids of DME were tested in two horizontal wells in the field, and their flowback fluids were collected and analyzed. The results show that the average droplet size of the flowback fluids in the wells using DME decreases with production time, and the altered wetting ability gradually returns to the level of the injected fracturing fluid. It can be confirmed that DME can migrate within the tight rock, make the rock surface more water-wet and enhance the imbibition capacity of the fracturing fluid, to reduce the reservoir pressure decline rate and increase production.

scholarly journals A mechanistic investigation of low salinity water flooding coupled with ion tuning for enhanced oil recovery

RSC Advances ◽  
2020 ◽  
Vol 10 (69) ◽  
pp. 42570-42583
Author(s):  
Rohit Kumar Saw ◽  
Ajay Mandal
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Calcite Dissolution ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Mechanistic Investigation ◽  
Salinity Water

The combined effects of dilution and ion tuning of seawater for enhanced oil recovery from carbonate reservoirs. Dominating mechanisms are calcite dissolution and the interplay of potential determining ions that lead to wettability alteration of rock surface.

scholarly journals Experimental and modeling study of wettability alteration through seawater injection in limestone: a case study

2020 ◽  
Vol 17 (3) ◽  
pp. 749-758
Author(s):  
Omolbanin Seiedi ◽  
Mohammad Zahedzadeh ◽  
Emad Roayaei ◽  
Morteza Aminnaji ◽  
Hossein Fazeli
Keyword(s):  
Oil Recovery ◽  
Contact Angle Measurement ◽  
Angle Measurement ◽  
Carbonate Reservoirs ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Indirect Contact ◽  
Molecular Kinetic Theory ◽  
Wet Condition

AbstractWater flooding is widely applied for pressure maintenance or increasing the oil recovery of reservoirs. The heterogeneity and wettability of formation rocks strongly affect the oil recovery efficiency in carbonate reservoirs. During seawater injection in carbonate formations, the interactions between potential seawater ions and the carbonate rock at a high temperature can alter the wettability to a more water-wet condition. This paper studies the wettability of one of the Iranian carbonate reservoirs which has been under Persian Gulf seawater injection for more than 10 years. The wettability of the rock is determined by indirect contact angle measurement using Rise in Core technique. Further, the characterization of the rock surface is evaluated by molecular kinetic theory (MKT) modeling. The data obtained from experiments show that rocks are undergoing neutral wetting after the aging process. While the wettability of low permeable samples changes to be slightly water-wet, the wettability of the samples with higher permeability remains unchanged after soaking in seawater. Experimental data and MKT analysis indicate that wettability alteration of these carbonate rocks through prolonged seawater injection might be insignificant.

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