Static Adsorption of an Ethoxylated Nonionic Surfactant on Carbonate Minerals

Adsorption behavior of in-house developed CO2-philic anionic surfactants

Incorporating CO2-philic functionalities into surfactant structure is proposed to address the drawbacks of conventional foaming agents such as premature rupture of lamellae in contact with oil, surfactant loss due to adsorption on rock or partitioning between oil and water, and salinity and temperature tolerance issues. Increased activity at the gas/water interface and less surfactant adsorption to the rock due to the presence of CO2-philic chains results in higher foam durability in the presence of oil. In the present paper, a comprehensive study on the adsorption of anionic CO2-philic surfactants onto sandstone rock surface is performed to understand adsorption mechanisms through the addition of CO2-philic tail groups in surfactant structure by observing the changes in concentration, static adsorption, and point of zero charge measurements. The static adsorption tests, Fourier Transform Infrared, and the X-ray Photoelectron Spectroscopy techniques were employed to investigate the interaction of surfactants with crushed Berea sandstone core sample at 90 °C. The static adsorption values of the S (single-tail), D (double-tail), and T (triple-tail) anionic surfactants were reported to be 0.53, 0.40, and 0.6 mg /g, respectively. The effect of alkali on the adsorption process of surfactants was also investigated and the adsorption of synthesized surfactants was found significantly low in alkaline conditions. A variety of analyses, including model fitting along with kinetics and thermodynamics studies at 30, 40, and 50 °C were performed to predict the adsorption behavior. The adsorption isotherm was found to best fit in Langmuir model. The process showed the best fit in the pseudo-second-order reaction kinetics model. The spontaneity of the adsorption process was verified by thermodynamic feasibility studies of the process.

Investigation of the Nonionic Acidizing Retarder AAO for Reservoir Stimulation

In the process of matrix acidizing, reducing the reaction rate between hydrochloric acid and carbonate rock to increase oil and gas production has become one of the biggest challenges in reservoir stimulation. An adsorption film formed on rocks can effectively postpone the contact between the hydrogen ion and rock, which is of great significance in decreasing the rate of an acid-rock reaction. In this study, nonionic acidizing retarder AAO was synthesized by acrylamide, allyl poly(ethylene glycol), and octadecyl methacrylate. The structure of AAO was characterized by Fourier transform infrared (FT-IR) spectrometry and 1H nuclear magnetic resonance (1H NMR). The reaction of AAO retard acid and 20% hydrochloric acid with CaCO3 was studied at 50 °C, and the amount of CO2 generated at different times was recorded. The etching time of 0.8% AAO retard acid to CaCO3 could be up to 120 min, whereas 20% hydrochloric acid (without AAO) ended at 45 min, which showed that AAO had the potential to defer the acid-rock reaction. The adsorption behavior of AAO on CaCO3 matched the pseudo-second-order kinetic model well. Meanwhile, the addition of urea greatly reduced the adsorption amount of AAO on CaCO3, which showed that the hydrogen bond was the driving force for the adsorption process. Additionally, the results of X-ray photoelectron spectroscopy (XPS) showed that the N element from acrylamide appeared on the surface of CaCO3 after adsorption. Scanning electron microscopy (SEM) demonstrated that a smooth and dense thin film existed on the surface of CaCO3 treated with AAO retard acid. The change in the vibration peak of C=O from 1720 to 1650 cm-1 indicated that the ester groups in AAO had been hydrolyzed, which was beneficial to film desorption and the reduction of reservoir damage. Therefore, this paper could help with research on carbonate acidizing for reservoir stimulation.

Temperature-Responsive Hydrogel Carrier for Reducing Adsorption Loss of Petroleum Sulfonates

As an effective anionic surfactant for chemical flooding, petroleum sulfonate (PS) is often used in conjunction with alkalis to reduce the adsorption loss of PS onto rock and clay surfaces. However, alkali injection can lead to scaling, aggravate the water-sensitive effect of clays, and accelerate polymer hydrolysis. Here, a temperature-responsive biohydrogel-based carrier (XLK) was designed to protect PS from adsorption onto geological features. XLK, an aqueous mixture containing 0.5% xanthan gum, 0.5% locust bean gum, and 2% KCl, was a gel at room temperature and transformed gradually into a sol above 50 °C (sol/gel transition temperature, Tsol/gel). Below the Tsol/gel, most PS was retained in the gel, preventing the adsorption of PS onto quartz sand. Above the Tsol/gel, PS was released into the surrounding medium. After it had been loaded with PS, the storage modulus (G', Pa) of XLK increased from 102 to 103 and the loss modulus (G″, Pa) increased from 101 to 102. Environmental scanning electron microscopy micrographs showed that PS filled gaps within the cross-linked network structure of XLK. Compared with the aqueous XLK formulation, the addition of hydrolyzed polyacrylamide (HPAM) decreased the melt rate of XLK and the interfacial tension (IFT) of PS. Among the constituents of XLK loaded with PS, KCl had the most obvious effect of lowering the shear modulus of HPAM. Sufficient amounts of KCl were effective in reducing the IFT of PS to ultralow levels (10-3 mN/m).

A review of wettability alteration using surfactants in carbonate reservoirs

The wettability of carbonate rocks is often oil-wet or mixed wet. A large fraction of oil is still remained in carbonate reservoirs, it is therefore of particular significance to implement effective methods to improve oil recovery from carbonate reservoirs. Altering wettability from oil-wet to more favorable water-wet has been proven successful to achieve this goal. Surfactants are widely investigated and served as wettability modifiers in this process. Yet a comprehensive review of altering wettability of carbonate reservoirs with surfactants is ignored in literature. This study begins with illustration of wettability evolution process in carbonate reservoirs. Techniques to evaluate wettability alteration extent or to reveal behind mechanisms are also presented. Several surfactant systems are analyzed in terms of their wettability alteration mechanisms, influential factors of performance, applicable conditions, and limitations. Mixture of different types of surfactants could obtain synergic effects, where applicable conditions are extended, and final performance is improved. Gemini surfactants have many desirable properties, which warrants further investigation for understanding their wettability alteration mechanisms and performance. At the end, this review discusses strategies related with surfactant cost, surfactant adsorption, and challenges at high temperature, high salinity reservoirs conditions. Also, some unclear issues are discussed.

Nanomaterials for subsurface application: study of particles retention in porous media

The ability to transport nanoparticles through porous media has interesting engineering applications, notably in reservoir capacity exploration and soil remediation. A series of core-flooding experiments were conducted for quantitative analysis of functionalized TiO2 nanoparticles transport through various porous media including calcite, dolomite, silica, and limestone rocks. The adsorption of surfactants on the rock surface and nanoparticle retention in pore walls were evaluated by chemical oxygen demand (COD) and UV–Vis spectroscopy. By applying TiO2 nanoparticles, 49.3 and 68.0 wt.% of surfactant adsorption reduction were observed in pore walls of dolomite and silica rock, respectively. Not surprisingly, the value of nanoparticle deposition for dolomite and silica rocks was near zero, implying that surfactant adsorption is proportional to nanoparticle deposition. On the other hand, surfactant adsorption was increased for other types of rock in presence of nanoparticles. 5.5, 13.5, and 22.4 wt.% of nanoparticle deposition was estimated for calcite, black and red limestone, respectively. By making a connection between physicochemical rock properties and nanoparticle deposition rates, we concluded that the surface roughness of rock has a significant influence on mechanical trapping and deposition of nanoparticles in pore-throats.

Universal scaling of adsorption of nonionic surfactants on carbonates using cloud point temperatures

HYPOTHESIS

Nonionic surfactants alter the wettability of oil-wet carbonate surfaces to a water-wet state. The degree of surfactant adsorption is expected to determine the extent of the wettability alteration. Furthermore, the structure of the hydrophobic and hydrophilic units of the surfactant should affect the degree of adsorption and correlate with the wettability alteration.

EXPERIMENTS

The adsorption on Indiana limestone was measured for nonionic surfactants with two different types of hydrophobic units and hydrophilic polyethoxylate units ranging from 15 to 40 mers. Measurements were conducted for several surfactant concentrations and temperatures.

FINDINGS

Adsorption increased with temperature and for surfactants with fewer hydrophilic groups. The adsorption occurs as micelles rather than individual surfactant molecules. An increase in adsorption is observed for the more hydrophobic surfactants at higher temperature and is attributed to the increase in micelle sizes. Adsorption collapses onto a universal curve as a function of the difference between cloud point of the surfactant and system temperature. At the same time wettability alteration was found to have a direct correlation with surfactant adsorption. These findings are critical for judicious selection of nonionic surfactants for analysis and design of wettability alteration for oil reservoirs.

Molecular Dynamics Simulations of Aqueous Nonionic Surfactants on a Carbonate Surface

The interactions and structure of secondary alcohol ethoxylates with 15 and 40 ethoxylate units in water near a calcite surface are studied. It is found that water binds preferentially to the calcite surface. Prediction of the free-energy landscape for surfactant molecules shows that single-surfactant molecules do not adsorb because they cannot get close enough to the surface because of the water layer for attractive ethoxylate-calcite or dispersion interactions to be significant. Micelles can adsorb onto the surface even with the intervening water layer because of the integrative effect of the attractive interactions of all the surfactant molecules. Adsorption is found to increase because of the closer proximity of the micelles to the surface due to a weakened water layer at higher temperatures. The free-energy well and barrier values are used to estimate surface to bulk partition coefficients for different surfactants and temperatures, and qualitative agreement is found with experimental observations. The combined effect of surfactant-water and surfactant-solid interactions is found to be responsible for an increased adsorption for nonionic surfactants as the system approaches the cloud point.

Role of Wettability on the Adsorption of an Anionic Surfactant on Sandstone Cores

We investigate the dynamic adsorption of anionic surfactant C_14 - 16 alpha olefin sulfonate on Berea sandstone cores with different surface wettability and redox states under high temperature that represents reservoir conditions. Surfactant adsorption levels are determined by analyzing the effluent history data with a dynamic adsorption model assuming Langmuir isotherm. A variety of analyses, including surface chemistry, ionic composition, and chromatography, is performed. It is found that the surfactant breakthrough in the neutral-wet core is delayed more compared to that in the water-wet core because the deposited crude oil components on the rock surface increase the surfactant adsorption via hydrophobic interactions. As the surfactant adsorption is satisfied, the crude oil components are solubilized by surfactant micelles and some of the adsorbed surfactants are released from the rock surface. The released surfactant dissolves in the flowing surfactant solution, thereby resulting in an overshoot of the produced surfactant concentration with respect to the injection value. Furthermore, under water-wet conditions, changing the surface redox potential from an oxidized to a reduced state decreases the surfactant adsorption level by 40%. We find that the decrease in surfactant adsorption is caused not only by removing the iron oxide but also by changing the calcium concentration after the core restoration process (calcite dissolution and ion exchange as a result of using EDTA). Findings from this study suggest that laboratory surfactant adsorption tests need to be conducted by considering the wettability and redox state of the rock surface while recognizing how core restoration methods could significantly alter the ionic composition during surfactant flooding.

Challenges and future of chemical assisted heavy oil recovery processes

The primary method for heavy oil and bitumen production across the world is still in-situ steam-based technology. There are some drawbacks associated with steam-driven heavy oil recovery methods such as cyclic steam stimulation (CSS), steam flooding, and steam-assisted gravity drainage (SAGD). These cons include the high greenhouse gas footprint, low heavy oil/bitumen recovery, and difficulty in stop operation in emergency conditions. There exists a need for an improved method for recovering residual oils after applying steam injection. One of the potential technologies for doing this is chemical assisted heavy oil recovery, especially alkaline and surfactant additives. But the challenging question is how to develop a chemical-based oil recovery method considering long-term steam-rock interactions. Several associated issues of chemical additives, including adsorption behavior of surfactant at reservoir conditions and thermal stability of surfactant at steam chamber temperature, make this question more complex. This paper addresses all these concerns and provides solid knowledge regarding this technology. We delve into newly formulated chemicals for coupling with thermal oil recovery techniques that are still limited to lab-scale research, with the need for further studies. This critical review also provides the opportunities and challenges associated with chemical assisted heavy oil/bitumen production in a post-steam injection scenario. Finally, different aspects of such a method are covered in this review, along with practical information on field trials and best practices across the world.

Two-Step Adsorption of a Switchable Tertiary Amine Surfactant Measured Using a Quartz Crystal Microbalance with Dissipation

The adsorption of a switchable cationic surfactant, N, N, N'-trimethyl- N'-tallow-1,3-diaminopropane (DTTM, Duomeen TTM), at the silica/aqueous solution interface is characterized using a quartz crystal microbalance with dissipation (QCM-D). The adsorption isotherms reveal that changes in the solution pH or salinity affect surfactant adsorption in competing ways. In particular, the combination of the degree of protonation of the surfactant and electrostatic interactions is responsible for surfactant adsorption. The kinetics of adsorption is carefully measured using the real-time measurement of a QCM-D, allowing us to fit the experimental data with analytical models. At pH values of 3 and 5, where the DTTM is protonated, DTTM exhibits two-step adsorption. This is representative of a fast step in which the surfactant molecules are adsorbed with head-groups orientated toward the surface, followed by a slower second step corresponding to formation of interfacial surfactant aggregates on the silica surface.

Thermoresponsive Pickering Emulsions Stabilized by Silica Nanoparticles in Combination with Alkyl Polyoxyethylene Ether Nonionic Surfactant

We put forward a simple protocol to prepare thermoresponsive Pickering emulsions. Using hydrophilic silica nanoparticles in combination with a low concentration of alkyl polyoxyethylene monododecyl ether (C₁₂E_n) nonionic surfactant as emulsifier, oil-in-water (o/w) emulsions can be obtained, which are stable at room temperature but demulsified at elevated temperature. The stabilization can be restored once the separated mixture is cooled and rehomogenized, and this stabilization-destabilization behavior can be cycled many times. It is found that the adsorption of nonionic surfactant at the silica nanoparticle-water interface via hydrogen bonding between the oxygen atoms in the polyoxyethylene headgroup and the SiOH groups on particle surfaces at low temperature is responsible for the in situ hydrophobization of the particles rendering them surface-active. Dehydrophobization can be achieved at elevated temperature due to weakening or loss of this hydrogen bonding. The time required for demulsification decreases with increasing temperature, and the temperature interval between stabilization and destabilization of the emulsions is affected by the surfactant headgroup length. Experimental evidence including microscopy, adsorption isotherms, and three-phase contact angles is provided to support the mechanism.