Browsing by Author "Hirasaki, George J."

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    A 2-D simulation study on CO2ﾠsoluble surfactant for foam enhanced oil recovery
    (Elsevier, 2019) Zeng, Yongchao; Farajzadeh, Rouhi; Biswal, Sibani L.; Hirasaki, George J.
    This paper probes the transport of CO2ﾠsoluble surfactant for foaming in porous media. We numerically investigate the effect of surfactant partitioning between the aqueous phase and the gaseous phase on foam transport for subsurface applications when the surfactant is injected in the CO2ﾠphase. A 2-D reservoir simulation is developed to quantify the effect of surfactant partition coefficient on the displacement conformance and CO2ﾠsweep efficiency. A texture-implicit local-equilibrium foam model is embedded to describe how the partitioning of surfactant between water and CO2ﾠaffects the CO2ﾠfoam mobility control when surfactant is injected in the CO2ﾠphase. We conclude that when surfactant has approximately equal affinity to both the CO2ﾠand the water, the transport of surfactant is in line with the gas propagation and therefore the sweep efficiency is maximized. Too high affinity to water (small partition coefficient) results in surfactant retardation whereas too high affinity to CO2ﾠ(large partition coefficient) leads to weak foam and insufficient mobility reduction. This work sheds light upon the design of water-alternating-gas-plus-surfactant-in-gas (WAGﾠ+ﾠS) process to improve the conventional foam process with surfactant-alternating-gas (SAG) injection mode during which significant amount of surfactant could possibly drain down by gravity before CO2ﾠslugs catch up to generate foam in situ the reservoir.
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    A Multiscale Study of Foam: The Phase Behavior, Transport, and Rheology of Foam in Porous Media
    (2017-12-01) Zeng, Yongchao; Hirasaki, George J.; Biswal, Sibani L.
    This dissertation provides an in-depth multiscale understanding of the foam flow in porous media for subsurface applications such as gas mobility control, aquifer remediation, CO2 sequestration, water production control etc. In enhanced oil recovery (EOR), gas flooding has superior crude oil displacement efficiency where the gas sweeps. However, the overall oil recovery is often not much better than that of water flooding because of viscous fingering, gravity override, and reservoir heterogeneity. Using surfactant to generate foam in situ the porous media offer promise to simultaneously address all the three issues mentioned. Yet, the successful design of foam projects requires insightful understanding of the phase/component transport and the rheology of foam flow in porous media. The first part of my research investigates the foam transport dependence on its constituent components: the effect of gas types and surfactant structures. An experimental investigation of the effect of gas type and surfactant structure is presented. The effects of gas solubility, the stability of lamellae, the surfactant Gibbs adsorption, and the gas diffusion rate across the lamellae were examined. Our experimental results showed that the steady-state foam strength is inversely correlated with the gas permeability across a liquid lamella, a parameter that characterizes the rate of mass transport. We also calculated the limiting capillary pressure for different foaming surfactants and found that foam stability is correlated with the Gibbs surface excess concentration. My research also advances the understanding of “smart” foam rheology that can improve the sweep efficiency of gas flooding in porous media. Laboratory research work was conducted to capture the effect of heterogeneity on foam using actual reservoir rocks of varied permeabilities. It is observed that foam is more stable in high permeability cores compared to low permeability cores. Such smart rheology was also visualized in a 3-layered heterogeneous micromodel at the pore-level. Foam was shown to respond to the porous media heterogeneity by separating into a relatively dry and wet regime in the high- and low-perm regions respectively. Due to the capillary continuity between the layers of different permeability, the phase separation induced a saturation step change between the layers which resulted in responsive flow resistance. In addition, understanding the foam-oil interaction is crucial to the success of foam EOR projects. In this thesis, foam strength dependence on oil was probed using nuclear magnetic resonance (NMR) imaging technique. Manganese (II) was doped into the surfactant solution to reduce the T_2 relaxation time of water in order to differentiate the NMR response from the oil. The measured apparent viscosity was mapped out with respect to different oil fractional flows and oil saturations. It is found out that the presence of oil can not only weaken the foam strength but also emulsify with the surfactant solution. Unlike the bulk foam column test with oil, the overall apparent viscosity is found to be dependent on both oil saturation (oil fractional flow) and oil composition. Moreover, improved numerical algorithm is developed to estimate foam model parameters based on laboratory-scale experiment for field-scale reservoir simulation. Both dry-out effect and shear-thinning rheology of foam were considered. The algorithm reduced the five-parameter estimation to a few simpler steps, such as linear regression and single-variable optimization, and successfully avoided the sensitivities of initial estimates and the non-uniqueness solution issues. Our improved algorithm was also compared with others reported in literature. The robustness of the algorithm was validated by varied foam systems. Last but not least, the idea of injecting the surfactant with the gas phase (WAG+S, water-alternating-gas-plus-surfactant-in-gas process) has been conceptualized for the next generation CO2 foam EOR. Some novel nonionic or switchable surfactants are CO2 soluble, thus making it possible to inject the surfactant with CO2 slugs. Since surfactant could be present in both the CO2 and aqueous phases, it is important to understand how the surfactant partitioning between the phases influences foam transport in porous media. Foam simulations were conducted in both 1-D and 2-D systems. We conclude that when surfactant has approximately equal affinity to both the CO2 and the water, the transport of surfactant is in line with the gas propagation and therefore the sweep efficiency is maximized.
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    A Study of Surface Treatments on Carbonate Core Material for Application to Mineral Precipitation and Dissolution during Geologic Carbon Storage
    (2013-06-05) Work, Sarah; Tomson, Mason B.; Bedient, Philip B.; Ward, C. H.; Hirasaki, George J.
    Underground injection of acid gas has been studied for several decades for oil field applications, such as enhanced oil recovery (EOR), but is now being studied as a solution to climate change. This research aims to simulate underground conditions at injection sites, such as the pilot scale injection site located near the site of a coal fired power facility in the Black Warrior Basin of Alabama. This proposed carbon capture and sequestration (CCS) location would involve injection of liquid CO2 into a carbonaceous saline aquifer. The objective of this study was to investigate carbonate surface treatments that alter the kinetics and mechanism of mineral dissolution resulting from the injection of an acid gas (CO2) into a geologic formation. A variety of mineral coatings were tested in an attempt to preserve mineral integrity under acidic conditions. Surface active chemicals were first tested, including scale inhibitors, followed by a novel acid induced surface treatment that precipitates an inorganic layer on the calcite to preserve the acid soluble mineral. These experiments are the first to investigate the use of scale inhibitors for mineral preservation, although were found ultimately to have little impact on dissolution kinetics. However, anions of moderate to strong acids induced surface coatings that were determined to effectively inhibit dissolution. Additionally, a novel, high pressure flow-through experimental apparatus was developed to simulate pressure and temperature conditions relevant to injection sites. Similar mineralogical studies in the literature have used pressurized, unstirred, batch systems to simulate mineral interactions. Solids with an acid induced surface coating were tested in the high pressure column and no calcium was found to leave the column.
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    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.
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    Accumulation of gas hydrates in marine sediments
    (2008) Bhatnagar, Gaurav; Hirasaki, George J.
    Generalized numerical models for simulating gas hydrate and free gas accumulation in marine sediments have been developed. These models include several physical processes such as phase equilibrium of gas hydrates, multiphase fluid flow in porous media, biogenic methane production, and sedimentation-compaction of sediments over geologic timescales. Non-dimensionalization of the models lead to the emergence of important dimensionless groups controlling these dynamic systems, such as the Peclet number, Damkohler number, and a sedimentation-compaction group that compares permeability to sedimentation rate. Exploring the entire parameter space of these dimensionless groups helps in delineating different modes of gas hydrate and free gas occurrence, e.g., no hydrate and hydrate with or without underlying free gas. Scaling schemes developed for these systems help in summarizing average gas hydrate saturation for hundreds of simulation results into two simple contour plots. The utility of these contour plots in predicting average hydrate saturation is shown through application to different geologic settings. The depth to the sulfate-methane transition (SMT) is also developed as an independent proxy for gas hydrate saturation for deep-source systems. It is shown through numerical modeling that scaled depth to the SMT correlates with the average gas hydrate flux through the gas hydrate stability zone (GHSZ). Later, analytical theory is developed for calculating steady-state concentration profiles as well as the complete gas hydrate saturation profile from the SMT depth. Application of this theory to several sites along Cascadia Margin indicates that SMT depth can be used as a fast and inexpensive proxy to get a first-order estimate of gas hydrate saturation, compared to expensive deep-drilling methods. The effect of overpressure development in low permeability gas hydrate systems is shown to have an important effect on gas hydrate and free gas saturations. Specifically, overpressure development decreases the net amount of gas hydrate and free gas in the system, in addition to extending the base of the hydrate stability zone below the seafloor by a relatively small depth. We also study the role of upward free gas migration in producing long, connected free gas columns beneath the gas hydrate layer. Finally, two-dimensional models are developed to study the effect of heterogeneities on gas hydrate and free gas distribution. Simulation results show that hydrate as well as free gas accumulates in relatively high saturations within these high permeability sediments, such as faults/fracture networks, dipping sand layers, and combinations of both, due to focused fluid flow.
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    Application of Foam for Mobility Control in Enhanced Oil Recovery (EOR) Process
    (2014-04-24) Cui, Leyu; Hirasaki, George J.; Miller, Clarence A.; Biswal, Sibani Lisa; Alvarez, Pedro J.
    This thesis focuses on the application of foam for mobility control in enhanced oil recovery (EOR) process. The performance of foam and surfactants was evaluated by systematic laboratory study. This includes the screening and evaluation of surfactant formulations for foam EOR process and the investigation of foam for mobility control at reservoir conditions. The adsorption of cationic surfactants on natural minerals was discussed in a separate chapter, although it is one aspect for evaluating surfactant formulations. A numerical model was used to fit the foam strength for foam flooding at reservoir conditions. The solubility, thermal and chemical stability and foaming ability of surfactant formulations were investigated in the screening and evaluation step. A qualified surfactant formulation for foam EOR should be soluble and stable from injection to reservoir conditions. The foaming ability of surfactant formulations needs to be verified in a porous media with crude oil. The bulk foam tests, i.e., foam height, equilibrium foam volume and foam half-life, are not suggested to be used for evaluating foaming ability of surfactant formulations, because of the poor correlation with foam tests in porous media. The detrimental effect of oil, especially for light crude oil, for foam stability was demonstrated. Foam boosters, e.g., betaine surfactants, can be used to stabilize the foam in the presence of crude oil. The mobility control ability of foam was evaluated in Silurian dolomite cores at reservoir conditions after screening and evaluation step. The apparent viscosity of foam was used to describe the mobility control ability. The higher apparent viscosity indicates the stronger foam and better mobility control ability. The strength of foam depends on foam quality, salinity and temperature. The influence of each parameter was investigated and illustrated by controlled experiments. Ethomeen C12 in formation brine and CO2 can generate strong foam at 120 °C and 3400 psi in a wide range of foam quality after the pressure gradient exceeded the minimum pressure gradient. The adsorption of cationic surfactant on the pure carbonate minerals is low owing to the repulsion of the electrostatic force. However, the natural carbonate minerals contain negatively charged impurities, e.g., silica and clays. The adsorption of cationic surfactants on these impurities was significant. Multivalent cations, i.e., Mg2+, Ca2+ and Al3+, can compete with cationic surfactants on the negatively charged binding sites to reduce the adsorption. The adsorption of Ethomeen C12 on silica was reduced from 5.33 mg/m2 in DI water to 3.31 mg/m2 in synthetic brine with 1.51×10-3 mol/L Al3+. The adsorption of Ethomeen C12 was measured at 2 atm CO2 to keep the solution clear. The method of methylene blue (MB) two-phase titration was improved to determine the cationic surfactant concentrations in high salinity brine. In summary, this study demonstrates the methodology to screen the surfactant formulations for the foam EOR process, elucidates the application of the foam for mobility control at reservoir conditions, improves the MB two-phase titration for cationic surfactant in high salinity brine and illuminates the reducing of the adsorption for cationic surfactants on natural carbonate minerals.
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    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 Lisa
    Nonionic 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.
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    Asphaltene Behavior in Crude Oil Systems
    (2013-10-31) Panuganti, Sai; Chapman, Walter G.; Vargas, Francisco M; Hirasaki, George J.; Tomson, Mason B.
    Asphaltene, the heaviest and most polarizable fraction of crude oil, has a potential to precipitate, deposit and plug pipelines, causing considerable production costs. The main objective of this study is to contribute to the thermodynamic and transport modeling of asphaltene in order to predict its precipitation, segregation and deposition. Potential calculation of some thermophysical properties of asphaltene is also explored. Predicting the flow assurance issues caused by asphaltene requires the ability to model the phase behavior of asphaltene as a function of pressure, temperature and composition. It has been previously demonstrated that the Perturbed Chain form of Statistical Association Fluid Theory (PC-SAFT) equation of state can accurately predict the phase behavior of high molecular weight compounds including that of asphaltene. Thus, a PC-SAFT crude oil characterization methodology is proposed to examine the asphaltene phase behavior under different operating conditions. With the fluid being well characterized at a particular reservoir depth, a compositional grading algorithm can be used to analyze the compositional grading related to asphaltene using PC-SAFT equation of state. The asphaltene compositional grading that can lead in some cases to the formation of a tar mat is studied using the same thermodynamic model. Quartz crystal microbalance experiments are performed to study the depositional tendency of asphaltene in different depositing environments. The possibility of simulating asphaltene deposition in a well bore is discussed by modeling the capillary data, which simultaneously accounts for asphaltene precipitation, aggregation and deposition. The work presented is expected to contribute to the calculation of thermophysical properties of hydrocarbons and in particular of asphaltene, characterization of crude oils, improve tools to model asphaltene phase behavior, check the quality of fluid samples collected and the accuracy of (pressure, volume and temperature) PVT tests, reduce the uncertainties related to reservoir compartmentalization, optimize the logging during data acquisition, prediction of tar mat occurrence depths, improved understanding of the asphaltene deposition process, and finally optimize the wellbore operating conditions to reduce the asphaltene deposit.
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    Characterization and rheology of water-in-oil emulsion from deepwater fields
    (2010) Alwadani, Mohammed S.; Hirasaki, George J.
    Seafloor pipeline transport of viscous crude oil may be problematic because of high oil viscosity. This problem is compounded when water cut increases and stable emulsions form that have apparent viscosities significantly exceeding the oil itself. Reducing such high viscosity requires better understanding of emulsion properties. This study focuses on the characterization of water-in-oil emulsions by nuclear magnetic resonance (NMR) and their rheological behavior with and without demulsifiers present. Experimental data from NMR experiments show that the emulsion is very stable and needs demulsifier that can enhance the coalescence between droplets and hence aid separation. With presence of an optimal nonionic demulsifier, emulsion viscosity can be reduced by as much as one order of magnitude and reaches the oil viscosity at high temperatures. The selection of optimal coalescer depends on operation conditions. Increasing the temperature requires more hydrophilic coalescer to separate water from oil. Knowledge of emulsion behavior at different conditions helps in selecting the optimum parameters in either the early design phase or the oilfield operation.
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    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.
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    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.
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    Correlations of NMR relaxation time with viscosity/temperature, diffusion coefficient and gas/oil ratio of methane-hydrocarbon mixtures
    (2000) Lo, Sho-Wei; Hirasaki, George J.; Kobayashi, Riki
    A 90 MHz NMR Spectrometer equipped with a high pressure probe was used to study relationship between NMR relaxation time and temperature, viscosity, diffusivity and gas/oil ratio of methane-hydrocarbon mixtures. This research project involves three parts: (1) modifications of the existing NMR apparatus. (2) Measurements of relaxation times and diffusion coefficients of methane-hydrocarbon mixtures. (3) Development of generalized correlations between transport properties and temperature and relaxation times. The NMR apparatus was modified in order to make elevated temperature and pressure measurements. The modifications included calibration of pressure transducers, addition of temperature measuring devices, connection to the high pressure sample probe of a sapphire sample cell and leak detection of the system. After the modifications, the apparatus was capable of measurements from 20 to 60°C at pressure up to 6000 psia. NMR relaxation measurements of three mixtures, methane-n-hexane, methane-n-decane and methane-n-hexadecane, were made. The log mean relaxation times were plotted against viscosity/temperature and it was found that unlike stock tank oils, they do not depend linearly on viscosity/temperature on a log-log scale. Each of the mixtures forms a different curve on the plot of relaxation time vs. viscosity/temperature. Diffusivity measurements were also made for these three mixtures, as well as pure hexane, decane and hexadecane. The log mean diffusion coefficients were calculated. The relationship between diffusion coefficients and relaxation times were studied, and it was found that diffusion coefficients depend linearly on T1 for pure hydrocarbons, but the dependence does not hold for methane-hydrocarbon mixtures. Correlations between transport properties and NMR relaxation times were developed. First, a relaxation time mixing rule was developed by studying the theory of NMR relaxation mechanism. From the mixing rule, it was found that departure of relaxation times of methane-n-alkane mixtures from linear correlation on a log-log scale can be correlated with proton fractions of methane, which can be expressed as gas/oil ratio. Thus, correlation between relaxation time, viscosity/temperature and gas/oil ratio was developed. Correlation between relaxation time, diffusivity and gas/oil ratio was also developed. From these correlations, viscosity and gas/oil ratio can be estimated just from NMR relaxation time and diffusion coefficient.
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    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.
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    Determination of fluid-phase-specific petrophysical properties of geological core for oil, water and gas phases
    (2024-03-05) Vinegar, Eva; Singer, Philip M.; Hirasaki, George J.; Chen, Zeliang; Wang, Xinglin; Vinegar, Harold J.; Rice University; Vinegar Technologies LLC; United States Patent and Trademark Office
    The following invention is used for determining the relative permeability of a fluid in a rock for three different phases: water, oil, and gas, in both conventional and unconventional formations. The permeability of a phase describes how much it can flow in porous media given a pressure gradient and is useful in evaluating reservoir quality and productivity. The following invention is a method to determine the three-phase relative permeabilities in both conventional and unconventional formations using NMR restricted diffusion measurements on core with NMR-active nuclei, combined with centrifugation of the core. In addition, the tortuosity, pore size (surface-to-volume ratio), fluid-filled porosity, and permeability is determined for each of the three phases in a rock.
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    Developing stable foams from polymeric surfactants for water production control
    (2005) Bhide, Vikram V.; Miller, Clarence A.; Hirasaki, George J.
    This research explores a new method using foams for water production control in an oilfield. Reducing water production during oil production is an important objective impacting the profitability of a mature oilfield. Currently practiced methods using gel or polymer based systems either offer inadequate water flow reduction or suffer problems of proper placement in the field. Because of its properties, foam has the potential for use in water control. In this study, foams stable in presence of flowing water (washout stability) were developed using polymeric surfactants. A screening test was developed to measure the washout resistance of various conventional and polymeric surfactants. Foam from several polymeric surfactants such as triblock F108 and hydrophobically modified HMPA1 exhibited remarkable improvement in washout stability over conventional surfactants. Strong foam that offered a large resistance to flow of water was generated in a two-foot long sand pack with some of these polymeric surfactants. Again, the polymeric surfactants exhibited higher foam washout resistance than the conventional surfactants as predicted by the screening tests. Investigation of surfactant desorption from an air-water interface using bubble shape analysis showed that this improved foam washout resistance was due to almost irreversible adsorption of polymeric surfactants. Collapse of foam from polymeric surfactants at long times in the screening test was determined to be due to hydrodynamic effects and not desorption. Also, foam washout stability with polymeric surfactants in sand pack was found to be limited by air dissolution into flowing water. Scale-up calculations for oilfield geometries showed that foam from F108 can be stable for a long enough time, even with gas dissolution, for the process to be practicable. Foam stable to residual oil, expected in the water producing zones, was created by mixing an anionic surfactant CS-330 with nonionic F108. This is because ionic surfactants produce an electrostatic barrier that prevents entry of oil droplets into the air water interface. Flowing oil, however, produced a stable emulsion with this surfactant combination which offered a large resistance to flow. This was undesirable and was minimized by a brine flush to remove surfactant from the aqueous phase of the foam region before contact with flowing oil.
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    Diluted bitumen emulsion characterization and separation
    (2010) Jiang, Tianmin; Miller, Clarence A.; Hirasaki, George J.
    Stable water-in-oil emulsions persist in bitumen froth from surface mining process of Athabasca oil sands because of asphaltenes and clay solids. This dissertation focuses on the characterization and separation of water in diluted bitumen emulsions. A novel approach to process experimental data from classic NMR experiments for the characterization of water in diluted bitumen emulsions has been proposed and tested. NMR PGSE restricted diffusion measurement can characterize emulsion drop size distribution. Experiments show that drop size of emulsion does not change much with time, which indicates that water in diluted bitumen emulsion is very stable without demulsifier. Water fraction profile and water droplet sedimentation velocity can be obtained from MRI 1-D T1 weighted profile measurement. Emulsion flocculation can be deduced by comparing the sedimentation velocity from experiment data and Stokes Law prediction. PR5 (a polyoxyethylene (EO)/polyoxypropylene (PO) alkylphenol formaldehyde resin) is an appropriate demulsifier for water in diluted bitumen emulsion. Almost complete separation can be obtained in the absence of clay solids. For the sample with solids, a rag layer containing solids with moderate density forms between the clean oil and free water layers. Partially oil-wet clay solids prevent complete separation of the emulsion. Experiments reveal that wettability of clay solids has significant effect on emulsion stability. Kaolinite with 100 ppm sodium naphthenate in toluene-brine mixture is chosen as model system for wettability test. Wettability of kaolinite can be altered by pH control, silicate and surfactant. Adding 3x10 -3 M Na2SiO3 at pH 10 can get 80% of kaolinite water-wet. Over 90% of kaolinite becomes water-wet adding C8TAB, betaine 13 and amine oxide DO with optimal dosages. In diluted bitumen emulsion, about 10-4 M sodium meta-silicate can change the wettability of solids from partially oil-wet to more water-wet. Hereby the clay solids can settle down to the aqueous phase and the separation is almost complete. Wettability of kaolinite can be characterized via zeta potential measurement and modeling. Simplified Gouy-Stern-Grahame model and oxide site-binding model can be used to correlate zeta potential of kaolinite in brine with different additives. Sodium silicates have the greatest effect per unit addition on changing zeta potential of kaolinite and can be used to change the wettability of clay solids. Almost complete separation be obtained by the three-step procedure: (a) adding 10-4 M Na2SiO3 during initial emulsion formation to make the solids less oil wet; (b) removing the clean oil formed following subsequent treatment with demulsifier and adding NaOH or Na2SiO3 with shaking to destroy the rag layer and form a relatively concentrated oil-in-water emulsion nearly free of solids; and (c) adding hydrochloric acid to break the oil-in-water emulsion.
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    Drainage of static and translating foam films
    (1997) Singh, Gurmeet; Miller, Clarence A.; Hirasaki, George J.
    Drainage of a mobile, symmetric, plane-parallel thin liquid film between two gas bubbles (foam film) is studied. An analytical solution for the rate of thinning of such a liquid film with an insoluble surfactant and having both film elasticity and surface viscosity is presented for the first time. Analysis is extended to the more general case of a soluble surfactant and compared with previous analyses. Surfactant material parameters affecting the rate of thinning are identified and grouped into a single dimensionless parameter, the surfactant number which describes the transition from a mobile to an immobile film. Significant deviation from the Reynolds velocity is found when this dimensionless parameter is small. Since draining foam or emulsion films are generally of nonuniform thickness with a thick region or 'dimple' as the central part and separated from the Plateau border by a thinner 'barrier ring', an analytical solution is not possible. Hence a numerical model was developed. This model simulates the hydrodynamics associated with the drainage of an axisymmetric, dimpled, mobile foam film with an insoluble surfactant. This extends the work of Joye (1994) which was limited to immobile films. Results of the parametric study indicate that the rate of drainage of these films is dependent on surfactant properties viz. elasticity, surface dilatational viscosity, surface shear viscosity and surface diffusivity. These properties are grouped into a single dimensionless parameter which is the same as obtained by our analytical solution for a plane parallel film and which correlates with the rate of drainage of the foam film. This parameter describes the transition from a mobile film to an immobile film. The simulations indicate considerable motion of the interface for draining mobile foam films. Foam texture in a porous medium is governed by the hydrodynamics of individual foam films (lamellae) flowing through pores of varying size. The stability of foam in a particular application depends upon the stability of a lamella in the porous medium, especially as the lamella expands in translating from a small pore (pore throat) to a larger pore (pore body). The numerical simulator developed above is extended to translating foam films to model the effect of various parameters on foam stability. The model predicts that the travelling lamella is unstable only for certain ranges of surfactant properties, porous media geometry and flow conditions, for e.g. gas flow rate and capillary pressure. Simulations show that mobile foam films stretch in going from a pore throat to a pore body and may thin down to the critical thickness and break, under certain conditions. In contrast immobile foam films are very stable due to an entrainment effect which occurs as the film expands in going from a pore throat to a pore body. The critical capillary pressure at which a moving lamella will break is determined as a function of film and porous medium properties. Further the concept of asymmetric drainage of foam films in porous media has been explored.
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    Dynamic aspects of emulsion stability
    (2004) Pena, Alejandro A.; Miller, Clarence A.; Hirasaki, George J.
    This dissertation encompasses novel theoretical, experimental and computational advances in the understanding of the transient behavior of emulsions undergoing phase separation. Firstly, the kinetics of dissolution of single drops of pure hydrocarbons and their mixtures in aqueous solutions of a nonionic surfactant (C12E8) was studied theoretically and experimentally. At moderate surfactant concentrations, both interfacial resistance to mass transfer and diffusion of micelles carrying solubilized oil dictated the solubilization rates. At high surfactant concentrations, the onset of spontaneously generated convection in the aqueous phase was observed. In such cases, convection aided mass transport in the bulk phase and reduced the diffusional resistance, thus leaving interfacial resistance as rate-controlling. Data suggest that the adsorption/fusion of micelles at the interfaces was the elementary molecular step within the kinetic mechanism that dictated the interfacial resistance to mass transport. Experimental results for the solubilization of single droplets were correlated without adjustable parameters with a plausible mass transfer model in agreement with such mechanism. This model was extended to polydisperse emulsions of hydrocarbons in nonionic surfactant solutions, and it was successfully applied to correlate data from experiments on solubilization in emulsions, Ostwald ripening and compositional ripening. In addition, a new experimental technique based on nuclear magnetic resonance (NMR) was developed to characterize emulsions. The contributions of this work include a novel theory to interpret results from NMR restricted diffusion experiments and an original procedure that couples diffusion measurements with transverse relaxation rate experiments to determine drop size distributions with arbitrary shape, the water/oil ratio of the emulsion and the rate of decay of magnetization at the interfaces, i.e., the surface relaxivity. It is shown that the procedure also allows identification of whether the dispersion is oil-in-water (O/W) or water-in-oil (W/O) in a straightforward manner and is suitable to evaluate changes in drop size distributions in time steps of approximately five minutes without manipulation or destruction of the sample. Finally, the effect of chemicals of known structure and composition (alkylphenol polyalkoxylated resins and polyurethanes) on the stability and properties of brine-in-crude-oil emulsions was assessed experimentally. (Abstract shortened by UMI.)
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    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.
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    Estimation of rock properties by NMR relaxation methods
    (1998) Huang, Chien-Chung; Hirasaki, George J.
    Two often used permeability models, which are based on logarithmic mean of relaxation time distribution and irreducible water, were examined. The model based on irreducible water was found to be more suitable than the model based on mean value of relaxation time distribution when oil is present. The NMR response of North Burbank with partial saturation of air and water is different from those of other sandstones. The increase in the amplitude of the microporosity part of the relaxation time distribution after desaturation was observed for North Burbank. The clay lining a pore is diffusionally coupled with the large pores when 100% water saturated. After desaturation with air, the water in the microchannel is isolated and relaxes like water in an isolated micropore. It is generally believed that when the rock is water-wet, there is tendency for water to occupy the small pores and contact the majority of the rock surface. Water is typically relaxed by contact with grain surface, but oil at the center of the pore has no access to these surfaces and therefore can only relax by bulk processes. According to this study, $T\sb1$ distributions under partial saturation with brine/Soltrol followed the above behavior. However, for $T\sb2$ distributions, we found the Soltrol peaks for chlorite-coated North Burbank and highly shaly sandstones were broadened and shortened to shorter relaxation times due to diffusion and internal gradients effects. The diffusion effect can be supported by the same observation in 100% S$\rm\sb{w}$ condition. This suggests even if oil is prevented from contacting the grain surface, oil will not necessarily relax as a bulk oil in water-wet system.