Browsing by Author "Puerto, Maura"
Now showing 1 - 11 of 11
Results Per Page
Sort Options
Item A systematic approach to alkaline-surfactant-foam flooding of heavy oil: microfluidic assessment with a novel phase-behavior viscosity map(Springer Nature, 2020) Vavra, Eric; Puerto, Maura; Biswal, Sibani L.; Hirasaki, George J.The apparent viscosity of viscous heavy oil emulsions in water can be less than that of the bulk oil. Microfluidic flooding experiments were conducted to evaluate how alkali-surfactant-foam enhanced oil recovery (ASF EOR) of heavy oil is affected by emulsion formation. A novel phase-behavior viscosity map—a plot of added salinity vs. soap fraction combining phase behavior and bulk apparent viscosity information—is proposed as a rapid and convenient method for identifying suitable injection compositions. The characteristic soap fraction, XSorsoap, is shown to be an effective benchmark for relating information from the phase-viscosity map to expected ASF flood test performance in micromodels. Characteristically more hydrophilic cases were found to be favorable for recovering oil, despite greater interfacial tensions, due to wettability alteration towards water-wet conditions and the formation of low apparent-viscosity oil-in-water (O/W) macroemulsions. Wettability alteration and bubble-oil pinch-off were identified as contributing mechanisms to the formation of these macroemulsions. Conversely, characteristically less hydrophilic cases were accompanied by a large increase in apparent viscosity due to the formation of water-in-oil (W/O) macroemulsions.Item Application of magnetic nanoparticles as demulsifiers for surfactant-enhanced oil recovery(Wiley, 2023) Zhang, Leilei; Bai, Chutian; Zhang, Zhuqing; Wang, Xinglin; Nguyen, Thao Vy; Vavra, Eric; Puerto, Maura; Hirasaki, George J.; Biswal, Sibani LisaNonionic surfactants are increasingly being applied in oil recovery processes due to their stability and low adsorption onto mineral surfaces. However, these surfactants lead to the production of emulsified oil that is extremely stable and difficult to separate by conventional methods. This research characterizes the stability of crude oil mixed with a nonionic surfactant, L24–22, in a brine solution. When subjected to gravity separation, a middle oil-rich and bottom water-rich emulsion are generated for various water–oil ratios. Thermal treatments can effectively break oil-rich emulsions, but the bottom water layer remains contaminated with micron-sized crude oil droplets. A magnetic nanoparticle treatment is shown to demulsify the crude oil emulsions, dropping the total organic carbon (TOC) in the water layer from 1470 to 30 ppm.Item Characterizing adsorption of associating surfactants on carbonates surfaces(Elsevier, 2018) Jian, Guoqing; Puerto, Maura; Wehowsky, Anna; Miller, Clarence; Hirasaki, George J.; Biswal, Sibani L.HYPOTHESIS: The adsorption of anionic surfactants onto positively charged carbonate minerals is typically high due to electrostatic interactions. By blending anionic surfactants with cationic or zwitterionic surfactants, which naturally form surfactant complexes, surfactant adsorption is expected to be influenced by a competition between surfactant complexes and surfactant-surface interactions. EXPERIMENTS: The adsorption behavior of surfactant blends known to form complexes was investigated. The surfactants probed include an anionic C15-18 internal olefin sulfonate (IOS), a zwitterionic lauryl betaine (LB), and an anionic C13-alcohol polyethylene glycol ether carboxylic acid (L38). An analytical method based on high-performance liquid chromatography evaporative light scattering detector (HPLC-ELSD) was developed to measure three individual surfactant concentrations from a blended surfactant solution. The adsorption of the individual surfactants and surfactant blends were systematically investigated on different mineral surfaces using varying brine solutions. FINDINGS: LB adsorption on calcite surfaces was found to be significantly increased when blended with IOS or L38 since it forms surfactant complexes that partition to the surface. However, the total adsorption of the LB-IOS-L38 solution on dolomite decreased from 3.09 mg/m2 to 1.97 mg/m2 when blended together compared to summing the adsorption values of individual surfactants, which highlights the importance of mixed surfactant association.Item Characterizing the Influence of Organic Carboxylic Acids and Inorganic Silica Impurities on the Surface Charge of Natural Carbonates Using an Extended Surface Complexation Model(American Chemical Society, 2019) Song, Jin; Rezaee, Sara; Zhang, Leilei; Zhang, Zhuqing; Puerto, Maura; Wani, Omar B.; Vargas, Francisco; Alhassan, Saeed; Biswal, Sibani L.; Hirasaki, George J.In this work, we developed an extended surface complexation model (SCM) that successfully fits all tested ζ-potential data (63 in total) of synthetic calcite and three natural carbonates (Iceland spar, Indiana limestone, “SME” rock from a Middle East field) in brines with divalent ions in a wide range of ionic strengths (0.001–0.5 M). To develop this extended model, our previous reported SCM is first optimized by incorporating the ζ-potential of synthetic calcite in a wide range of ionic strength (0.001–0.5 M) along with previously published data for parameter refitting. The model is then applied to predict the surface charge of synthetic calcite in concentrated solutions up to 5 M NaCl to reveal the role of high salinity in calcite wettability. Eventually, the model is extended to fit the ζ-potential of natural carbonates by adding surface reactions for impurities such as silica and organic-based carboxylic acids. The coverage of the organic impurities is found to be essential for explaining why the ζ-potential of natural carbonates is more negative compared to that of synthetic calcite. Naphthenic acid (assumed to have one carboxylic group) and humic/fulvic acid (assumed to have six carboxylic groups) are tested in the model calculation as possible sources of surface impurities to demonstrate the effect of the number of carboxylic groups in the acid molecule. Finally, the effect of a humic acid pretreatment on the ζ-potential of synthetic calcite is investigated experimentally to verify the assumption that absorbed organic impurities on the calcite surface contribute significantly to a more negatively charged natural carbonate surface when compared to that of pure calcite surfaces.Item Destabilization, Propagation, and Generation of Surfactant-Stabilized Foam during Crude Oil Displacement in Heterogeneous Model Porous Media(American Chemical Society, 2018) Xiao, Siyang; Zeng, Yongchao; Vavra, Eric D.; He, Peng; Puerto, Maura; Hirasaki, George J.; Biswal, Sibani L.Foam flooding in porous media is of increasing interest due to its numerous applications such as enhanced oil recovery, aquifer remediation, and hydraulic fracturing. However, the mechanisms of oil-foam interactions have yet to be fully understood at the pore level. Here, we present three characteristic zones identified in experiments involving the displacement of crude oil from model porous media via surfactant-stabilized foam, and we describe a series of pore-level dynamics in these zones which were not observed in experiments involving paraffin oil. In the displacement front zone, foam coalesces upon initial contact with crude oil, which is known to destabilize the liquid lamellae of the foam. Directly upstream, a transition zone occurs where surface wettability is altered from oil-wet to water-wet. After this transition takes place, a strong foam bank zone exists where foam is generated within the porous media. We visualized each zone using a microfluidic platform, and we discuss the unique physicochemical phenomena that define each zone. In our analysis, we also provide an updated mechanistic understanding of the "smart rheology" of foam which builds upon simple "phase separation" observations in the literature.Item Effect of Surfactant Partitioning Between Gaseous Phase and Aqueous Phase onﾠCO2ﾠFoam Transport for Enhanced Oil Recovery(Springer, 2016) Zeng, Yongchao; Ma, Kun; Farajzadeh, Rouhi; Puerto, Maura; Biswal, Sibani L.; Hirasaki, George J.CO2 flood is one of the most successful and promising enhanced oil recovery technologies. However the displacement is limited by viscous fingering, gravity segregation and reservoir heterogeneity. Foaming the CO2 and brine with a tailored surfactant can simultaneously address these three problems and improve the recovery efficiency. Commonly chosen surfactants as foaming agents are either anionic or cationic in class. These charged surfactants are insoluble in either CO2 gas phase or supercritical phase and can only be injected with water. However, some novel nonionic or switchable surfactants are CO2 soluble, thus making it possible to be injected with the CO2 phase. Since surfactant could be present in both CO2 and aqueous phases, it is important to understand how the surfactant partition coefficient influences foam transport in porous media. Thus, a 1-D foam simulator embedded with STARS foam model is developed. All test results, from different cases studied, have demonstrated that when surfactant partitions approximately equally between gaseous phase and aqueous phase, foam favors oil displacement in regard with apparent viscosity and foam propagation speed. The test results from the 1-D simulation are compared with the fractional flow theory analysis reported in literature.Item Evaluating the Transport Behavior of CO2ﾠFoam in the Presence of Crude Oil under High-Temperature and High-Salinity Conditions for Carbonate Reservoirs(American Chemical Society, 2019) Jian, Guoqing; Zhang, Leilei; Da, Chang; Puerto, Maura; Johnston, Keith P.; Biswal, Sibani L.; Hirasaki, George J.An amine-based surfactant, Duomeen TTM, was evaluated for foam flooding in carbonate rock at high temperature (120 °C), high salinity (22% total dissolved solids), and CO2–oil miscible conditions. We demonstrate enhanced oil recovery by utilizing CO2 foam under miscible conditions in the presence of crude oil. The foam was generated in situ by both co-injection and surfactant alternating gas injection modes. Foam transport and propagation were characterized as a function of the foam quality, shear rate, permeability, surfactant concentration, and method of injection. Finally, we utilize the experimental results to obtain the parameters for the STARS foam model by optimizing multiple variables related to the dry out, shear thinning, and surfactant concentration effects on foam transport. Enhanced oil recovery utilizing CO2 foam under miscible conditions in the presence of SMY crude oil was able to decrease oil saturation to 3.0%. It was also determined that significantly more injected pore volumes were required for the foam to reach the steady state in the presence of SMY crude oil. A foam simulation process in a heterogeneous reservoir is conducted applying the parameters obtained. The TTM CO2 foam generated significantly reduces the mobility of CO2 in the high permeability layers, which results in an improved swept volume in the low permeability zone that significantly improves oil recovery when epoil = 1 and fmoil = 0.5. Oil saturation parameters play important roles in the effectiveness of CO2 foam: large epoil and small fmoil will reduce the efficiency for TTM CO2 foam.Item Insights on Foam Transport from a Texture-Implicit Local-Equilibrium Model with an Improved Parameter Estimation Algorithm(American Chemical Society, 2016) Zeng, Yongchao; Muthuswamy, Aarthi; Ma, Kun; Wang, Le; Farajzadeh, Rouhi; Puerto, Maura; Vincent-Bonnieu, Sebastien; Akbar Eftekhari, Ali; Wang, Ying; Da, Chang; Joyce, Jeffrey C.; Biswal, Sibani L.; Hirasaki, George J.We present an insightful discussion on the implications of foam transport inside porous media based on an improved algorithm for the estimation of model parameters. A widely used texture-implicit local-equilibrium foam model, STARS, is used to describe the reduction of gas mobility in the state of foam with respect to free gas. Both the dry-out effect and shear-dependent rheology are considered in foam simulations. We estimate the limiting capillary pressure Pc* from fmdryvalues in the STARS model to characterize foam film stability in a dynamic flowing system. We find that Pc* is a good indicator of foam strength in porous media and varies with different gas types. We also calculate Pc* for different foaming surfactants and find that foam stability is correlated with the Gibbs surface excess concentration. We compare our improved parameter estimation algorithm with others reported in literature. The robustness of the algorithm is validated for various foam systems.Item Measuring in-situ capillary pressure of a flowing foam system in porous media(Elsevier, 2022) Vavra, Eric; Puerto, Maura; Bai, Chutian; Ma, Kun; Mateen, Khalid; Biswal, Lisa; Hirasaki, GeorgeHypothesis: Capillary pressure (Pc) is an intrinsic property of aqueous foams that has been demonstrated to play an important role in lamella rupture. Thus, directly measuring in-situ capillary pressure of a foam flowing through porous media has potential to greatly improve understanding of this complex process. Experiments: A capillary pressure probe was constructed and validated. Direct measurements of capillary pressure were made at ambient conditions during foam quality scan experiments in a transparent 1.41 × 10−10 m2 (143-Darcy) homogenous sand pack conducted at constant gas velocity. The foam texture was simultaneously visualized at the wall of the sand pack via microscope. Findings: In the low-quality regime, a plateauing trend in Pc was identified. In-situ microscopic visualization of the flowing foam revealed that gas bubbles were convecting with a fine discontinuous texture while Pc is at the plateau value Ppc. In the high-quality regime, the measured capillary pressures first decreased with increasing quality before increasing again at the driest qualities. These changes in Pc correlated with foam bubbles becoming coarser with increasing injected gas fractional flow before transitioning to continuous-gas flow at the slowest and driest injection conditions. These findings have been previously unreported for steady-state flow conditions and shall have significant implications for the general physical description of foam flow in porous media.Item Surface Complexation Modeling of Calcite Zeta Potential Measurements in Brines with Mixed Potential Determining Ions (Ca2+, CO32-, Mg2+, SO42-) for Characterizing Carbonate Wettability(Elsevier, 2017) Song, Jin; Zeng, Yongchao; Wang, Le; Duan, Xindi; Puerto, Maura; Chapman, Walter G.; Biswal, Sibani L.; Hirasaki, George J.This study presents experiment and surface complexation modeling (SCM) of synthetic calcite zeta potential in brine with mixed potential determining ions (PDI) under various CO2 partial pressures. Such SCM, based on systematic zeta potential measurement in mixed brines (Mg2+, SO42−, Ca2+ and CO32−), is currently not available in the literature and is expected to facilitate understanding of the role of electrostatic forces in calcite wettability alteration. We first use a double layer SCM to model experimental zeta potential measurements and then systematically analyze the contribution of charged surface species. Calcite surface charge is investigated as a function of four PDIs and CO2 partial pressure. We show that our model can accurately predict calcite zeta potential in brine containing a combination of four PDIs and apply it to predict zeta potential in ultra-low and pressurized CO2 environments for potential application in enhanced oil recovery in carbonate reservoirs. Model prediction reveals that calcite surface will be positively charged in all considered brines in pressurized CO2 environment (>1 atm). The calcite zeta potential is sensitive to CO2 partial pressure in the various brine in the order of Na2CO3 > Na2SO4 > NaCl > MgCl2 > CaCl2 (Ionic strength = 0.1 M).Item Ultra-low-tension compositions and their use in enhanced oil recovery(2018-01-02) Puerto, Maura; Salinas, José Luis López; Miller, Clarence A.; Hirasaki, George; Rice University; United States Patent and Trademark OfficeIn some embodiments, the present disclosure pertains to compositions for enhanced oil recovery. In some embodiments, such compositions include: (1) a first agent, wherein the first agent acts as a foam booster; (2) a second agent, wherein the second agent includes a sulfonated or sulfated anionic surfactant; a (3) a third agent, wherein the third agent includes an alkoxylated and anionic surfactant; and (4) a base liquid. In some embodiments, the compositions of the present disclosure further include a gas, such as nitrogen. Further embodiments of the present disclosure pertain to methods of formulating the aforementioned compositions for enhanced oil recovery. Additional embodiments of the present disclosure pertain to methods of recovering oil from a reservoir by utilizing the aforementioned compositions.