Screening of Surfactants for Flooding at High-Mineralization Conditions: Two Production Zones of Carbonate Reservoir

The selection of effective surfactants potentially can mobilize oil up to 50% of residuals in mature carbonate oilfields. Surfactants’ screening for such oilfields usually is complicated by the high salinity of water, high lipophilicity of the rock surface, and the heterogeneous structure. A consideration of features of the oilfield properties, as well as separate production zones, can increase the deep insight of surfactants’ influence and increase the effectiveness of surfactant flooding. This article is devoted to the screening of surfactants for two production zones (Bashkirian and Vereian) of the Ivinskoe carbonate oilfield with high water salinity and heterogeneity. The standard core study of both production zones revealed no significant differences in permeability and porosity. On the other hand, an X-ray study of core samples showed differences in their structure and the presence of microporosity in the Bashkirian stage. The effectiveness of four different types of surfactants and surfactant blends were evaluated for both production zones by two different oil displacement mechanisms: spontaneous imbibition and filtration experiments. Results showed the higher effect of surfactants on wettability alteration and imbibition mechanisms for the Bashkirian cores with microporosity and a higher oil displacement factor in the flooding experiments for the Vereian homogeneous cores with lower oil viscosity.

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

10.1115/omae2021-63603 ◽

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.

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

SPE Journal ◽

10.2118/208581-pa ◽

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.

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

SPE Journal ◽

10.2118/194194-pa ◽

2019 ◽

Vol 24 (03) ◽

pp. 1092-1107 ◽

Cited By ~ 7

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.

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A Model for Wettability Alteration in Fractured Reservoirs

SPE Journal ◽

10.2118/174555-pa ◽

2015 ◽

Vol 20 (06) ◽

pp. 1261-1275 ◽

Cited By ~ 12

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.

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

Polymers ◽

10.3390/polym12102241 ◽

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.

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

SPE Journal ◽

10.2118/175027-pa ◽

2016 ◽

Vol 21 (04) ◽

pp. 1126-1139 ◽

Cited By ~ 17

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.

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

Petroleum Science ◽

10.1007/s12182-019-00412-1 ◽

2020 ◽

Vol 17 (3) ◽

pp. 712-721 ◽

Cited By ~ 8

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

Petroleum Science ◽

10.1007/s12182-020-00537-8 ◽

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.

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Study on oil displacement efficiency of offshore sandstone reservoir with big bottom water

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-021-01201-6 ◽

2021 ◽

Author(s):

Jie Tan ◽

Ying-xian Liu ◽

Yan-lai Li ◽

Chun-yan Liu ◽

Song-ru Mou

Keyword(s):

Bottom Water ◽

High Water ◽

Displacement Efficiency ◽

Oil Displacement ◽

Oil Displacement Efficiency ◽

Sandstone Reservoir ◽

Sandstone Reservoirs ◽

High Water Cut Stage ◽

High Water Cut ◽

Water Cut

AbstractX oilfield is a typical sandstone reservoir with big bottom water in the Bohai Sea. The viscosity of crude oil ranges from 30 to 425 cp. Single sand development with the horizontal well is adopted. At present, the water content is as high as 96%. The water cut of the production well is stable for a long time in the high water cut period. The recoverable reserves calculated by conventional methods have gradually increased, and even the partial recovery has exceeded the predicted recovery rate. This study carried out an oil displacement efficiency experiment under big water drive multiple to accurately understand an extensive bottom water reservoir's production law in an ultra-high water cut stage. It comprehensively used the scanning electron microscope date, casting thin section, oil displacement experiment, and production performance to analyze the change law of physical properties and relative permeability curve from the aspects of reservoir clay minerals, median particle size, pore distribution, and pore throat characteristics. Therefore, the development law of horizontal production wells in sandstone reservoirs with big bottom water is understood. It evaluates the ultimate recovery of sandstone reservoirs with big bottom water. It provides a fundamental theoretical basis and guidance for dynamic prediction and delicate potential tapping of sandstone reservoirs with big bottom water at a high water cut stage.

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

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.236-238.2135 ◽

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.

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