Thesis (Ph. D.)--University of Texas at Austin, 2003. / Vita. Includes bibliographical references. Available also from UMI Company.

Thesis (Ph. D.)--University of Missouri-Columbia, 1998. / Typescript. Vita. Includes bibliographical references (leaves 154-161). Also available on the Internet.

Anthropogenic CO₂ captured from a coal-fired power plant can be used for an enhanced oil recovery (EOR) operation while mitigating the atmospheric impact of CO₂ emissions. Concern about climate change caused by CO₂ emissions has increased the motivation to develop carbon capture and sequestration (CCS) projects to reduce the atmospheric impact of coal and other fossil fuel combustion. Enhanced oil recovery operations are typically constrained by the supply of CO₂, so there is interest from oil producers to use large-volume anthropogenic (LVA) CO₂ for tertiary oil production. The intermittency of LVA CO2 emissions creates an area of concern for both oil producers and electric utilities that may enter into a CO₂ supply contract for EOR. An oil producer wants to know if intermittency from a non-standard source of CO₂ will impact oil production from the large volume being captured. Since the electric utility must supply electricity on an as-needed basis, the CO₂ emissions are inherently intermittent on a daily and seasonal basis. The electric utility needs to know if the intermittent supply of CO₂ would reduce its value compared to CO₂ delivered to the oil field at a constant rate. This research creates an experimental test scenario where one coal-fired power plant captures 90% of its CO₂ emissions which is then delivered through a pipeline to an EOR operation. Using real emissions data from a coal-fired power plant and simplified data from an actual EOR reservoir, a series of reservoir simulations were done to address and analyze potential operational interference for an EOR operator injecting large-volume, intermittent CO₂ characteristic of emissions from a coal-fired power plant. The test case simulations in this study show no significant impact to oil production from CO₂ intermittency. Oil recovery, in terms of CO₂ injection, is observed to be a function of the total pore volumes injected. The more CO₂ that is injected, the more oil that is produced and the frequency or rate at which a given volume is injected does not impact net oil production. Anthropogenic CO₂ sources can eliminate CO₂ supply issues that constrain an EOR operation. By implementing this nearly unlimited supply of CO₂, oil production should increase compared to smaller-volume or water-alternating-gas (WAG) injection strategies used today. Mobility ratio and reservoir heterogeneity have a considerable impact on oil recovery. Prediction of CO₂ breakthrough at the production wells seems to be more accurate when derived from the mobility ratio between CO₂ and reservoir oil. The degree of heterogeneity within the reservoir has a more direct impact on oil recovery and sweep efficiency over time. The volume of CO₂ being injected can eventually invade lower permeability regions, reducing the impact of reservoir heterogeneity on oil recovery. This concept should mobilize a larger volume of oil than a conventional volume-limited or WAG injection strategy that may bypass or block these lower permeability regions. Besides oil recovery, a reservoir's performance in this study is defined by its CO₂ injectivity over time. Elevated injection pressures associated with the large-volume CO₂ source can substantially impact the ability for an oil reservoir to store LVA CO₂. As CO₂, a less viscous fluid, replaces produced oil and water, the average reservoir pressure slowly declines which improves injectivity. This gradual improvement in injectivity is mostly occupied by the increasing volume of recycled CO₂. Sweep efficiency is critical towards minimizing the impact of CO₂ recycling on reservoir storage potential. Deep, large, and permeable oil reservoirs are more capable of accepting LVA CO₂, with less risk of fracturing the reservoir or overlying confining unit. The depth of the reservoir will directly dictate the injection pressure threshold in the oil reservoir as the fracture pressure increases with depth. If EOR operations are designed to sequester all the CO₂ delivered to the field, additional injection capacity and design strategies are needed. / text

Chemical flooding is one of the most difficult enhanced oil recovery methods and was considered a high-risk process in the past. Some reasons are low and uncertain oil price, high chemical prices, lack of confidence in performance of the chemical flooding process, long project life, and reservoir and process uncertainties. However, with significant improvement in simulation and optimization tools and high oil price, chemical flooding is feasible in terms of economical and carefully implemented design. Optimization of chemical floods requires complex integration of reservoir, chemical, economics properties and also drilling and production strategies. Many of these variables are uncertain parameters and many simulations are required to capture the effect of the uncertain and decision variables. These simulations could become very expensive and may not be feasible to consider all of the required simulation models. The goal of this research is the development of a methodology for optimization and design of chemical flooding of candidate oil reservoirs. We performed a comprehensive sensitivity study of reservoir and fluid properties that have significant influence on the oil production during the chemical flooding by performing a series of reservoir simulation runs. For performing the reservoir simulation runs, this study used the UT_IRSP platform and the multiphase, multicomponent, chemical flooding simulator called UTCHEM. During the study, UT_IRSP and UTCHEM have been modified by adding new modules, functions and variables. For example, a deviated well module was implemented in UTCHEM to study deviated wells. Deviated well module allows the users to introduce deviated wells in reservoir and import the well locations similar to Eclipse or CMG simulators. A time-dependent well schedule module was implemented in the UT_IRSP framework. This enhancement allows the well placement optimization studies to find the best time to add new wells, and change the status of the well for example from a producer to an injector in order to have an optimum development plan. An advanced post processing module was added to UT_IRSP in order to design, screen, and optimize complex cases for chemical enhanced oil recovery processes such as investigating the well patterns, well spacing, and type of the well (horizontal vs. vertical wells). An experimental design and response surface methodology with integrated economic model were utilized in this study to obtain the optimum design under uncertainties and have an optimal combination of the decision variables. This methodology is based on applying multi-regression analysis and ANOVA (analysis of variance) between the objective function (i.e. dependent variable, which is net present value (NPV) in chemical flooding) and other uncertain and process variables (independent variables). The economic analysis model used the discounted cash flow method to calculate net present value at the economic life of process, internal rate of return, and growth rate of return for each simulation case. Also the optimizer, OptQuest, is launched with a goal of maximizing the mean NPV. The range and the risk associated with the optimum design was studied using Monte Carlo simulation of objective function of the response variable and other independent variables. This methodology was applied for complex chemical flood cases such as well placement, change of status of wells as a function of time or well pattern and well spacing to investigate the best well scenario from recovery and economics point of view. / text

Chemical Enhanced Oil Recovery methods have been growing in popularity as a result of the depletion of conventional oil reservoirs and high oil prices. These processes are significantly more complex when compared to waterflooding and require detailed engineering design before field-scale implementation. Coreflood experiments that have been performed on reservoir rock are invaluable for obtaining parameters that can be used for field-scale flooding simulations. However, the design used in these floods may not always scale to the field due to heterogeneities, chemical retention, mixing and dispersion effects. Reservoir simulators can be used to identify an optimum design that accounts for these effects but uncertainties in reservoir properties can still cause poor project results if it not properly accounted for. Different reservoirs will be investigated in this study, including more unconventional applications of chemical flooding such as a 3md high-temperature, carbonate reservoir and a heterogeneous sandstone reservoir with very high initial oil saturation. The goal of the research presented here is to investigate the impact that select reservoir uncertainties can have on the success of the pilot and to propose methods to reduce the sensitivity to these parameters. This research highlights the importance of good mobility control in all the case studies, which is shown to have a significant impact on the economics of the project. It was also demonstrated that a slug design with good mobility control is less sensitive to uncertainties in the relative permeability parameters. The research also demonstrates that for a low-permeability reservoir, surfactant propagation can have a significant impact on the economics of a Surfactant-Polymer Flood. In addition to mobilizing residual oil and increasing oil recovery, the surfactant enhances the relative permeability and this has a significant impact on increasing the injectivity and reducing the project life. Injecting a high concentration of surfactant also makes the design less sensitive to uncertainties in adsorption. Finally, it was demonstrated that for a heterogeneous reservoir with high initial oil saturation, optimizing the salinity gradient will significantly increase the oil recovery and will also make the process less sensitive to uncertainties in the cation exchange capacity. / text

Operators can improve a reservoir’s value by optimizing it in a more holistic manner, or over its entire life cycle. This thesis developed approaches to life cycle optimization, with emphasis on accessible technical and economic modeling techniques for production. The challenges of life cycle optimization are properly scheduling the times at which the operator should switch from one recovery phase to the next, along with determining other field design parameters such as well spacing and injection pressures for waterflooding and enhanced oil recovery processes. To deliver the most value, the operator needs to produce from a reservoir the greatest quantity of oil, at a relatively low cost, reasonably soon, and ideally at a time when the oil price is high. This is quite a tall order, as these goals are often in conflict. This thesis extended existing research regarding lifecycle optimization, first modeling production from a reservoir using an exponential decline model and assuming the oil price’s behavior can be approximated with mean-reverting processes. Implications of operating and capital costs potentially being correlated with the oil price were also examined. Finally, a mean-reverting price model that forecasts the mean oil price as increasing and described by a logistic model was proposed to accommodate both recent price forecasts and economic reality. As exponential decline models are more appropriate for characterizing existing production history rather than making a priori predictions, a geologic-parameter-based model was developed using a tank model for primary recovery and a model based on Koval theory and parameterizing a reservoir in terms of flow capacity and storage capacity for waterflooding and CO2 flooding. This model was adapted from existing theory to account for situations where a waterflood has incompletely swept a reservoir at the start of CO2 flooding. Analytical expressions were also derived for estimating injection rates into a formation parameterized by flow capacity and storage capacity. The geologic-parameter-based model was combined with economic assumptions and optimized using a genetic algorithm. This optimization suggested an operator should switch from primary recovery to a CO2 flood with a large WAG ratio relatively early in the reservoir’s life. / text

The effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg[superscript 2+] and SO4[superscript 2-] and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca[superscript 2+], but without Mg[superscript 2+] or SO₄[superscript 2-] was unsuccessful in changing calcite wettability. Modified seawater containing Mg[superscript 2+] and SO₄[superscript 2-], and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO₄[superscript 2-] and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs. / text

Protein mechanical responses play a critical role in a wide variety of biological phenomena, impacting events as diverse as muscle contraction and stem cell differentiation. Recent advances in both experimental and computational techniques have provided the opportunity to explore protein constitutive properties at the molecular level. However, despite these advances many questions remain about how proteins respond to applied mechanical forces, particularly as a function of load magnitude. In order to address these questions, relatively simple helical structures were computationally tested to determine the mechanisms and kinetics of unfolding at a range of physiologically relevant load magnitudes. Atomically detailed constant force molecular dynamics simulations combined with the Milestoning kinetic analysis framework revealed that the mean first passage time (MFPT) of the initiation of unfolding of long (~16nm) isolated helical domains was a non-monotonic function of the magnitude of applied tensile load. The unfolding kinetics followed a profile ranging from 2.5ns (0pN) to a peak of 3.75ns (20pN) with a decreasing MFPT beyond 40pN reflected by an MFPT of 1ns for 100pN. The application of the Milestoning framework with a coarse-grained network analysis approach revealed that intermediate loads (15pN-25pN) retarded unfolding by opening additional, slower unfolding pathways through non-native [pi]-helical conformations. Analysis of coiled-coil helical pairs revealed that the presence of the second neighboring helix delayed unfolding initiation by a factor of 20, with calculated MFPTs ranging from 55ns (0pN) to 85ns (25pN per helix) to 20ns (100pN per helix). The stability of the coiled-coil domains relative to the isolated helix was shown to reflect a decreased propensity to break flexibility restraining intra-helix hydrogen bonds, thereby delaying [psi] backbone dihedral angle rotation and unfolding. These results show for the first time a statistically determined profile of unfolding kinetics for an atomically detailed protein that is non-monotonic with respect to load caused by a change in the unfolding mechanism with load. Together, the methods introduced for analyzing the mechanical response of proteins as well as the timescales determined for the initiation of unfolding provide a framework for the determination of the constitutive properties of proteins and non-biological polymers with more complicated geometries. / text

The purpose of the work resulting in this report is to develop a mechanically enhanced breaking bar, or prying bar, for bringing down trees. There was already a prototype to study, which was assembled by welded steel components. A specification of demands took form after continuous technical discussions with the inventor, assignee and mentors. When an analysis of this device and its function was made, the work continued with calculations to establish the foundation to design a mechanical model. Geometrical relationships were established to design the sub-components of the breaking bar and its functions. Simulations regarding material strength and mechanical function were made by the use of different modules in the CAD-software Solid Works and led to a simplified version of the breaking bar. The new simplified version was accepted by the inventor and the drawings for the new tool could now be made. During the time of this work the inventor has prepared his patent request and therefore this work has been classified and considered under secrecy for the inner circle persons containing the Kogertek-employees. The breaking bar which was produced with its powerful gear ratio is amplifying the force from the handle by a factor 25 and lifts 50 mm in the felling cut of the tree. In theory the tool would weigh approximately 1800 grams and can be used to bring down a tree with a diameter of at most 40 cm. Drawings for the constituent components were sent to a workshop to be manufactured and a mechanical breaking bar was assembled and tested.

No description available.