<p>The rising carbon dioxide emissions contributing to climate change has lead to the examination of potential ways to mitigate the environmental impact. One such method is through the geological sequestration of carbon (CCS). Although there are several different forms of geological sequestration (i.e. Saline Aquifers, Oil and Gas Reservoirs, Unminable Coal Seams) the current projects are just initiating the large scale-testing phase. The lead entry point into CCS projects is to combine the sequestration with enhanced oil recovery (EOR) due to the improved economic model as a result of the oil recovery and the pre-existing knowledge of the geological structures. The potential scope of CCS-EOR projects throughout the continental United States in terms of a systematic examination of individual reservoir storage potential has not been examined. Instead the majority of the research completed has centered on either estimating the total United States storage potential or the potential of a single specific reservoir.</p><p>The purpose of this paper is to examine the relationship between oil recovery, carbon dioxide storage and cost during CCS-EOR. The characteristics of the oil and gas reservoirs examined in this study from the Nehring Oil and Gas Database were used in the CCS-EOR model developed by Sean McCoy to estimate the lifting and storage costs of the different reservoirs throughout the continental United States. This allows for an examination of both technical and financial viability of CCS-EOR as an intermediate step for future CCS projects in other geological formations. </p><p>One option for mitigating climate change is to store industrial CO2 emissions in geologic reservoirs as part of a process known as carbon capture and storage (CCS). There is general consensus that large-scale deployment of CCS would best be initiated by combining geologic sequestration with enhanced oil recovery (EOR), which can use CO2 to improve production from declining oil fields. Revenues from the produced oil could help offset the current high costs of CCS. </p><p>The cumulative potential of CCS-EOR in the continental U.S. has been evaluated in terms of both CO2 storage capacity and additional oil production. This thesis examines the same potential, but on a reservoir-by-reservoir basis. Reservoir properties from the Nehring Oil and Gas Database are used as inputs to a CCS-EOR model developed by McCoy (YR) to estimate the storage capacity, oil production and CCS-EOR costs for over 10,000 oil reservoirs located throughout the continental United States. </p><p>We find that 86% of the reservoirs could store &#8804;1 y or CO2 emissions from a single 500 MW coal-fired power plant (i.e., 3 Mtons CO2). Less than 1% of the reservoirs, on the other hand, appear capable of storing &#8805;30 y of CO2 emissions from a 500 MW plan. But these larger reservoirs are also estimated to contain 48% of the predicted additional oil that could be produced through CCS-EOR. The McCoy model also predicts that the reservoirs will on average produce 4.5 bbl of oil for each ton of sequestered CO2, a ratio known as the utilization factor. This utilization factor is 1.5 times higher that arrived at by the U.S. Department of Energy, and leads to a cumulative production of oil for all the reservoirs examined of ~183 billion barrels along with a cumulative storage capacity of 41 Mtons CO2. This is equivalent to 26.5 y of current oil consumption by the nation, and 8.5 y of current coal plant emissions.</p> / Thesis

Statistic data indicates that about 100,000 tones of waste tire were generated each year. Current recycling market of waste tire is very small. Therefore, many waste tires remain untreated and cause severe health and safety problems in storage. PP fiber cut end is the waste material after cutting off the fiber. Traditional reuse way was to be the toy¡¦s fillers. If we can reuse the materials properly to develop a market of additional value, it will be a big contribution to the society. In this research, recycled waste tire powder and PP fiber cut end are used as oil adsorbents for the purpose of oil recovery during the process of oil spill emergency response. PP fiber cut end and waste tire powder are capable of adsorbing oil due to their hydrophobic surface property and the capillary forces developed during the contact with oil, therefore, makes them a perfect material for oil recovery. The major advantage of recycled PP fiber cut end is its high oil adsorbing capacity (approximately 48.4g/g). But, after reuse, its oil adsorbing speed was slow down, so does the oil adsorbing capacity. On the other hand, with good elasticity, the waste tire powder can be reused for more than 100 times without loosing its capability. However, the oil adsorbing capacity of waste tire powder is far less than PP fiber (approximately 2.84g/g). Finally, we combine PP fiber cut end and waste tire powder, to see if we can take the advantage of each product and make the best utilization of the composite material. Results indicate the composite material can be reused for more than 100 times without loosing its capability, and its performance is even better than the combination of each individual product. In the other test, we can see the composite material can not only adsorb engine oil and crude oil, but also adsorb emulsified oil. In the test, the composite material can recover up to 28 times of its own weight of oil. With the invented set up, the oil recover work is much easier to operate, and moreover, the composite material is less expensive. Only a squeeze roller and a collection container are required to recover oil. So, the composite material is indeed having practicability and mobility. Finally, the composite material is an excellent adsorbent compares with other products available on the market.

Thesis (M.S.)--Mississippi State University. Department of Geosciences. / Title from title screen. Includes bibliographical references.

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