Concerns about elevated atmospheric carbon dioxide (CO 2 ) and the effect on global climate have created proposals for the reduction of carbon emissions from large stationary sources, such as power plants. Carbon dioxide capture and sequestration (CCS) in deep geologic units is being considered by Florida electric-utilities. Carbon dioxide-enhanced oil recovery (CO 2 -EOR) is a form of CCS that could offset some of the costs associated with geologic sequestration. Two potential reservoirs for geologic sequestration were evaluated in south-central and southern Florida: the Paleocene Cedar Keys Formation/Upper Cretaceous Lawson Formation (CKLIZ) and the Lower Cretaceous Sunniland Formation along the Sunniland Trend (Trend). The Trend is a slightly arcuate band in southwest Florida that is about 233 kilometers long and 32 kilometers wide, and contains oil plays within the Sunniland Formation at depths starting around 3,414 meters below land surface, which are confined to mound-like structures made of coarse fossil fragments, mostly rudistids. The Trend commercial oil fields of the South Florida Basin have an average porosity of 16% within the oil-producing Sunniland Formation, and collectively have an estimated storage capacity of around 26 million tons of CO 2 . The Sunniland Formation throughout the entire Trend has an average porosity of 14% and an estimated storage capacity of about 1.2 billion tons of CO 2 (BtCO2 ). The CKLIZ has an average porosity of 23% and an estimated storage capacity of approximately 79 BtCO 2 . Porous intervals within the CKLIZ and Sunniland Formation are laterally homogeneous, and low-permeability layers throughout the units provide significant vertical heterogeneity. The CKLIZ and Sunniland Formation are considered potentially suitable for CCS operations because of their geographic locations, appropriate depths, high porosities, estimated storage capacities, and potentiallyeffective seals. The Trend oil fields are suitable for CO 2 -EOR in the Sunniland Formation due to appropriate injected-CO 2 density, uniform intergranular porosity, suitable API density of formation-oil, sufficient production zones, and adequate remaining oil-in-place following secondary recovery. In addition to these in-depth investigations of the CKLIZ and Sunniland Formation, a more-cursory assessment of deep geologic units throughout the state of Florida, which includes rocks of Paleocene and Upper Cretaceous age through to rocks of Ordovician age, shows additional units in Florida that may be suitable for CO 2 -EOR and CCS operations. Furthermore, this study shows that deep geologic units throughout Florida potentially have the capacity to sequester billions of tons of CO 2 for hundreds of fossil-fuel-fired power plants. Geologic sequestration has not yet been conducted in Florida, and its implementation could prove useful to Florida utility companies, as well as to other energy-utilities in the southeastern United States.

Accurate, non-invasive determination of multiphase fluids distribution in reservoir rock can greatly help the evaluation and monitoring of oil reservoirs. This laboratory thesis research, carried but utilizing the biomedical engineering concepts and measurement facilities, is an important step in developing a novel magnetic field-based oil detection method. When paramagnetic nanoparticles are either adsorbed oil/water interface or dispersed in a fluid phase in reservoir rock pores, and exposed to external magnetic field, the resultant particle movements displace the interface. Interfacial tension acts as a restoring force, leading to interfacial fluctuation and a pressure (sound) save. As the first step, the motion of the interface between a suspension of paramagnetic nanoparticles and a non-magnetized fluid (placed in a cylindrical dish) is measured by phase-sensitive optical coherence tomography (PS-OCT). Experiments were carried out with a range of iron-oxide nanoparticles that were synthesized and surface-coated by our Chemical Engineering collaborators. The numerical method was improved to be volume conserving, and extended to 3D, for more quantitative matching. The measurements of interfacial motion by PS-OCT confirm theoretical predictions of the frequency doubling and importance of material properties, such as the particle size, for the interface displacements. The relative densities of the fluid phase(air/aqueous and dodecane/aqueous) strongly affect the interfacial displacement. Next, the acoustic responses to the external magnetic oscillation, from the rock samples into which different aqueous dispersions of nanoparticles were injected, were measured in terms of the magnetic frequency, nanoparticle concentration, and other process parameters. Subsequently, the PS-OCT displacements in response to the external magnetic oscillation, from the rock samples into which different aqueous dispersions of nanoparticles were injected, were also measured in terms of the magnetic frequency, nanoparticle concentration, and other process parameters. Conclusions and the recommendations for further study are then given. / text

Chemical enhanced oil recovery has regained its attention because of high oil price and the depletion of conventional oil reservoirs. This process is more complex than the primary and secondary recovery flooding and requires detailed engineering design for a successful field-scale application. An effective alkaline/co-solvent/polymer (ACP) formulation was developed and corefloods were performed for a cost efficient alternative to alkaline/surfactant/polymer floods by the research team at the department of Petroleum and Geosystems Engineering at The University of Texas at Austin. The alkali agent reacts with the acidic components of heavy oil (i.e. 170 cp in-situ viscosities) to form in-situ natural soap to significantly reduce the interfacial tension, which allows producing residual oil not contacted by waterflood or polymer flood alone. Polymer provides mobility control to drive chemical slug and oil bank. The cosolvent added to the chemical slug helps to improve the compatibility between in-situ soap and polymer and to reduce microemulsion viscosity. An impressive recovery of 70% of the waterflood residual oil saturation was achieved where the remaining oil saturation after the ACP flood was reduced to only 13.5%. The results were promising with very low chemical usage for injection. The UTCHEM chemical flooding reservoir simulator was used to model the coreflood experiments to obtain parameters for pilot scale simulations. Geological model was based on unconsolidated reservoir sand with multiple seven spot well patterns. However, facility capacity and field logistics, reservoir heterogeneity as well as mixing and dispersion effects might prevent coreflood design at laboratory from large scale implementation. Field-scale sensitivity studies were conducted to optimize the design under uncertainties. The influences of chemical mass, polymer pre-flush, well constraints, and well spacing on ultimate oil recovery were closely investigated. This research emphasized the importance of good mobility control on project economics. The in-situ soap generated from alkali-naphthenic acid reaction not only mobilizes residual oil to increase oil recovery, but also enhances water relative permeability and increases injectivity. It was also demonstrated that a closer well spacing significantly increases the oil recovery because of greater volumetric sweep efficiency. This thesis presents the simulation and modeling results of an ACP process for a viscous oil in high permeability sandstone reservoir at both coreflood and pilot scales. / text

Surfactant related recovery processes are of increasing interest and importance because of high oil prices and the urge to meet energy demand. High oil prices and the accompanying revival of EOR operations have provided academia and industry with great opportunities to test alkaline surfactant polymer (ASP) methods on a field scale and to develop novel surfactant systems that can improve the performance of such EOR processes. This dissertation intends to discuss both opportunities through two unique projects, the development of novel surfactants for EOR applications and the design for an alkaline/surfactant/polymer (ASP) field pilot. In Section I of this dissertation, a novel series of anionic Gemini surfactants are carefully synthesized and systematically investigated. The remarkable abilities of Gemini surfactants to influence oil-water interfaces and aqueous solution properties are fully demonstrated. These surfactants are shown to have great potential for application in EOR processes. A wide range of Gemini structures (C₁₄ to C₂₄ chain length, -C2- and -C4- spacers, sulfate and carboxylate head groups) was synthesized and shown to have high aqueous solubility, with Krafft points below 20°C. The critical micelle concentrations (CMC) for these new molecules are measured to be orders of magnitude lower than their conventional counterparts. The significantly more negative Gibbs free energy for Gemini surfactant drives the micellization process and results in ultralow CMC. An adsorption study of Gemini surfactants at air-water and solid-water interfaces shows their superior surface activity from tighter molecular packing, and attractive characteristics of low adsorption loss at the solid surface. All anionic Gemini surfactants synthesized have an extraordinary tolerance to salinity and/or hardness. No phase separation or precipitation occurs in the aqueous stability tests, even in the presence of extremely high concentrations of mono- and/or di-valent ions. Moreover, ultra-low IFT values are reached under these conditions for Type I microemulsion systems, at very low surfactant concentrations. The stronger molecular interaction between the Gemini and conventional surfactants offers synergy that promotes aqueous stability and interfacial activity. Gemini molecules with short spacers are capable of giving rise to high viscosities at fairly low concentrations. The rheological behavior can be explained by changes in the micellar structure. A molecular thermodynamic model is developed to study anionic Gemini surfactants aggregation behavior in solution. The model takes into account of the head group-counter-ion binding effect and utilizes two simplified solutions to the Poisson-Boltzmann equation. It properly predicts the CMC of the surfactants synthesized and can be easily expanded to investigate other factors of interest in the micellization process. Section II of this dissertation studies chemical formulation design and implementation for an oilfield where an alkaline/surfactant/polymer (ASP) pilot is being carried out. A four-step systematic design approach, composed of a) process and material selection; b) formulation optimization; c) coreflood validation; 4) lab-scale simulation, was successfully implemented and could be easily transferred to other EOR projects. The optimal chemical formulation recovered over 90% residual oil from Berea coreflood. Lab-scale simulation model accurately history matches the coreflood experiment and sets the foundation for pilot-scale numerical study. Different operating strategies are investigated using a pilot-scale model, as well as the sensitivities of project economics to various design parameters. A field execution plan is proposed based on the results of the simulation study. A surface facility conceptual design is put together based on the practical needs and conditions in the field. Key lessons learned throughout the project are summarized and are invaluable for planning and designing future pilot floods. / text

Carbon Dioxide (CO₂) Enhanced Oil Recovery (EOR) is becoming an important bridge to commercialize geologic sequestration (GS) in order to help reduce anthropogenic CO₂ emissions. Current U.S. environmental regulations require operators to monitor operational and groundwater aquifer changes within permitted bounds, depending on the injection activity type. We view one goal of monitoring as maximizing the chances of detecting adverse fluid migration signals into overlying aquifers. To maximize these chances, it is important to: (1) understand the limitations of monitoring pressure versus geochemistry in deep aquifers (i.e., >450 m) using analytical and numerical models, (2) conduct sensitivity analyses of specific model parameters to support monitoring design conclusions, and (3) compare the breakthrough time (in years) for pressure and geochemistry signals. Pressure response was assessed using an analytical model, derived from Darcy's law, which solves for diffusivity in radial coordinates and the fluid migration rate. Aqueous geochemistry response was assessed using the numerical, single-phase, reactive solute transport program PHAST that solves the advection-reaction-dispersion equation for 2-D transport. The conceptual modeling domain for both approaches included a fault that allows vertical fluid migration and one monitoring well, completed through a series of alternating confining units and distinct (brine) aquifers overlying a depleted oil reservoir, as observed in the Texas Gulf Coast, USA. Physical and operational data, including lithology, formation hydraulic parameters, and water chemistry obtained from field samples were used as input data. Uncertainty evaluation was conducted with a Monte Carlo approach by sampling the fault width (normal distribution) via Latin Hypercube and the hydraulic conductivity of each formation from a beta distribution of field data. Each model ran for 100 realizations over a 100 year modeling period. Monitoring well location was varied spatially and vertically with respect to the fault to assess arrival times of pressure signals and changes in geochemical parameters. Results indicate that the pressure-based, subsurface monitoring system provided higher probabilities of fluid migration detection in all candidate monitoring formations, especially those closest (i.e., 1300 m depth) to the possible fluid migration source. For aqueous geochemistry monitoring, formations with higher permeabilities (i.e., greater than 4 x 10⁻¹³ m²) provided better spatial distributions of chemical changes, but these changes never preceded pressure signal breakthrough, and in some cases were delayed by decades when compared to pressure. Differences in signal breakthrough indicate that pressure monitoring is a better choice for early migration signal detection. However, both pressure and geochemical parameters should be considered as part of an integrated monitoring program on a site-specific basis, depending on regulatory requirements for longer term (i.e., >50 years) monitoring. By assessing the probability of fluid migration detection using these monitoring techniques at this field site, it may be possible to extrapolate the results (or observations) to other CCUS fields with different geological environments. / text

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The performance of Enhanced Oil Recovery (EOR) processes is adversely affected by the heterogeneous distribution of flow properties of the rock. The effects of heterogeneity are further highlighted when the mobility ratio between the displacing and the displaced fluids is unfavorable. Polymer flooding aims to mitigate this by controlling the mobility ratio resulting in an increase in the volumetric swept efficiency. However, the design of the polymer injection process has to take into account the uncertainty due to a limited knowledge of the heterogeneous properties of the reservoir. Numerical reservoir models equipped with the most updated, yet uncertain information about the reservoir should be employed to optimize the operational settings. Consequently, the optimal settings are uncertain and should be revised as the model is updated. In this report, a feedback-control scheme is proposed with a model updating step that conditions prior reservoir models to newly obtained dynamic data, and this followed by an optimization step that adjusts well control settings to maximize (or minimize) an objective function. An illustration of the implementation of the proposed closed-loop scheme is presented through an example where the rate settings of a well affected by water coning are adjusted as the reservoir models are updated. The revised control settings yield an increase in the final value of the objective function. Finally, a fast analog of a polymer flooding displacement that traces the movement of random particles from injectors to producers following probability rules that reflect the physics of the actual displacement is presented. The algorithm was calibrated against the full-physics simulation results from UTCHEM, the compositional chemical flow simulator developed at The University of Texas at Austin. This algorithm can be used for a rapid estimation of basic responses such as breakthrough time or recovery factor and to provide a simplified characterization the reservoir heterogeneity. This report is presented to fulfill the requirements to obtain the degree of Master of Science in Engineering under fast track option. It summarizes the research proposal presented for my doctorate studies that are currently ongoing. / text

Stacked storage systems are a viable carbon management operation, especially in regions with potential growth in CO₂ enhanced oil recovery (EOR) projects. Under a carbon constrained environment, the industrial Texas Gulf Coast is an ideal area for development of stacked storage operations, with a characteristically high CO₂ intensity and abundance of aging oil fields. The development of EOR along the Texas Gulf Coast is limited by CO₂ supply constraints. A stacked storage system is implemented with an EOR project to manage the temporal differences between the operation of a coal-fired power plant and EOR production. Currently, most EOR operations produce natural CO₂ from geologic formations. A switch to anthropogenic CO₂ sources would require an EOR operator to handle volumes of CO₂ beyond EOR usage. The use of CO₂ in an EOR operation is controlled and managed to maximize oil production, but increasing injection rates to handle the volume of CO₂ captured from a coal plant can decrease oil production efficiency. With stacked storage operations, a CO₂ storage reservoir is implemented with an EOR project to maintain injection capacity equivalent to a coal plant's emissions under a carbon constrained environment. By adding a CO₂ storage operation, revenue can still be generated from EOR production, but it is considerably less than just operating an EOR project. The challenge for an efficient stacked storage project is to optimize oil production and maximize profits, while minimizing the revenue reduction of pure carbon sequestration. There is an abundance of saline aquifers along the Texas Gulf Coast, including the Wilcox, Vicksburg, and Miocene formations. To make a stacked storage system more viable and reduce storage costs, maximizing injectivity is critical, as storage formations are evaluated on a cost-per-ton injected basis. This cost-per-ton injected criteria, also established as injection efficiency, incorporates reservoir injectivity and depth dependant drilling costs to determine the most effective storage formation to incorporate with an EOR project. With regionally adequate depth to maximize injectivity while maintaining reasonable drilling costs, the Vicksburg formation is typically the preferred storage reservoir in a stacked storage system along the Texas Gulf Coast. Of the eleven oil fields analyzed on a net present value basis, the Hastings field has the greatest potential for both EOR and stacked storage operations. / text

With a number of advantages hitherto unrecognized, nanoparticle-stabilized emulsions and foams have recently been proposed for enhanced oil recovery (EOR) applications. Long-distance transport of nanoparticles is a prerequisite for any such EOR applications. The transport of the particles is limited by the degree to which the particles are retained by the porous medium. In this work, experiments that quantify the retention and provide insight into the mechanisms for nanoparticle retention in porous media are described. Sedimentary rock samples (Boise sandstone and Texas Cream limestone) were crushed into single grains and sieved into narrow grain size fractions. In some cases, clay (kaolinite or illite) was added to the Boise sandstone samples. These grain samples were packed into long (1 ft – 15 ft) slim tubes (ID = 0.93 cm) to create unconsolidated sandpack columns. The columns were injected with aqueous dispersions of silica-cored nanoparticle (with and without surface coating) and flushed with brine. The nanoparticle effluent concentration history was measured and the nanoparticle recovery was calculated as a percentage of the injected nanoparticle dispersion. Fifty experiments were performed in this fashion, varying different experimental parameters while maintaining others constant to allow direct comparisons between experiments. The parameters analyzed in this thesis are: specific surface area of the porous medium, lithology, brine salinity, interstitial velocity, residence time, column length, and temperature. Our results indicate that retention is not severe, with an 8% average of the injected amount, for all our experiments. From the parameters analyzed, specific surface area was the most influential variable, with a linear effect on nanoparticle retention independently of lithology. Salinity increased nanoparticle retention slightly and delayed nanoparticle arrival. Velocity, residence time and length are coupled parameters and were studied jointly; they had a minor effect on retention. Temperature had a marginal effect, as we observed an approximate 2% increase in retention at 80°C compared to 21°C. Both surface coated and bare silica nanoparticles were successfully transported, so surface coating does not appear to be a prerequisite for transport for the particle and rock systems studied. / text

Polymers play a key role in several EOR processes such as polymer flooding, surfactant-polymer flooding and alkaline-surfactant-polymer flooding due to their critical importance of mobility control in achieving high oil recovery from these processes. Numerical simulators are used to predict the performance of all of these processes and in particular the injection rate of the chemical solutions containing polymer; since the economics is very sensitive to the injection rates. Injection rates are governed by the injection viscosity, thus, it is very important to model the polymer viscosity accurately. For the predictions to be accurate, not only the viscosity model must be accurate, but also the calculation of equivalent shear rate in each gridblock must be accurate because the non-Newtonian viscosity models depend on this shear rate. As the size of the gridblock increases, the calculation of this velocity becomes less numerically accurate, especially close to wells. This research presents improvements in polymer viscosity model. Using the improvements in shear thinning model, the laboratory polymer rheology data was better matched. For the first time, polymer viscosity was modeled for complete range of velocity using the Unified Viscosity Model for published laboratory data. New models were developed for relaxation time, time constant and high shear viscosity during that match. These models were then used to match currently available HPAM polymer's laboratory data and predict its viscosity for various concentrations for full flow velocity range. This research presents the need for injectivity correction when large grid sizes are used. Use of large grid sizes to simulate large reservoir due to computation constraints induces errors in shear rate calculations near the wellbore and underestimate polymer solution viscosity. Underestimated polymer solution viscosities lead to incorrect injectivity calculation. In some cases, depending on the well grid block size, this difference between a fine scale and a coarse simulation could be as much as 100%. This study focuses on minimizing those errors. This methodology although needs some more work, but can be used in accurate predictions of reservoir simulation studies of chemical enhanced oil recovery processes involving polymers. / text