<p> Nuclear magnetic resonance (NMR) has become an increasingly important tool for estimating porosity, permeability, and fluid characteristics in oil and gas reservoirs since its introduction in the 1950s. While NMR has become common practice in <i>conventional</i> reservoirs, its application is relatively new to <i>unconventional</i> reservoirs such as the Eagle Ford Shale. Porosity and permeability estimates prove difficult in these exceptionally tight rocks and are routinely below the detection limit and/or resolution of low frequency (2 MHz or less) NMR. High frequency (400 MHz) NMR has been applied to address these issues; however, previous studies have been limited to crushed rock samples or millimeter-sized core plugs. </p><p> In response, a custom-built NMR probe has been constructed, capable of measuring 0.75-inch diameter, 0.45-inch length core plugs at 400 MHz, to determine if larger core plug sizes yield higher resolution <i>T</i>₂ distributions in the Eagle Ford Shale. The tool is composed of two primary elements, the structural framework and the radio frequency circuit. Each element was designed and constructed iteratively to test various layouts while maintaining functionality. The probe's structural design was initially based on retired, commercial probes then modified to operate within a Bruker Ascend&trade; 400WB NMR spectrometer. Designs were drafted and 3D-printed multiple times to determine proper physical dimensions and clearances. Once designs were deemed satisfactory, structural components were manufactured and assembled to create the structural framework. A radio frequency circuit was then built to measure <i>T</i>₂ distributions at the desired frequency and sample size. Multiple inductor designs and capacitor combinations were tested until a stable circuit, capable of matching impedance and tuning to the proper frequency, was achieved. The probe's stability and data quality were then confirmed by measuring the NMR spectra of deuterated water in a Teflon container. </p><p> The NMR probe was validated by comparing high frequency (400 MHz) data acquired in-house to low frequency (2 MHz) data measured at a commercial laboratory. Twelve core plugs (0.75-inch diameter, 1-inch length) were cut from two Eagle Ford Shale subsurface cores located in Gonzales and La Salle counties, Texas. Low frequency <i>T</i>₂ distributions were measured twice: first after drying core plug samples in a vacuum oven and again after spontaneous imbibition with various brine solutions (deionized water, 8 wt.% KCl, or 17.9 wt.% KCl) for one week. These contrasting saturation states were applied to highlight immovable water in the core plugs. For high frequency data measurements, samples were trimmed to 0.45-inch lengths to fit inside the newly-built NMR probe, leaving two sub-samples for each of the original core plugs. <i> T</i>₂ distributions were first acquired "as-is" (e.g., without drying or imbibition). After as-is data acquisition, samples were dried in a vacuum oven then allowed to spontaneously imbibe the same brine solutions used in the low frequency study. <i>T</i>₂ distributions were measured again after imbibition and compared to the low frequency data acquired by the commercial laboratory. </p><p> Qualitatively, high frequency <i>T</i>₂ distributions resemble low frequency data; however, the absolute <i>T</i>₂ values are routinely higher by one order of magnitude. The difference may be caused by data acquisition, data processing, fluid-rock interactions, magnetic field inhomogeneities, or some combination thereof. In spite of not attaining the higher-resolution <i>T</i>₂ distributions desired, the project still provides a proof-of-concept that <i>T</i>₂ relaxation times can be measured in conventional-sized core plugs using 400 MHz NMR. Although limited in its outcomes, the study delivers promising results and elicits future research into utilizing high frequency NMR spectroscopy as a petrophysical tool for unconventional reservoirs.</p><p>

<p> Reactive transport phenomena, such as CO2 sequestration and Microbial EOR, have been of interest in streamline-based simulations. Tracing streamlines launched from a wellbore is important, especially for time-sensitive transport behaviors. However, discretized gridblocks are usually too large as compared to the wellbore radius. Field-scale simulations with local-grid-refinement (LGR) models often consume huge computational time. An embedded grid-free approach to integrate near-wellbore transport behaviors into streamline simulations is developed, which consists of two stages of development: tracing streamlines in a wellblock (a gridblock containing wells) and coupling streamlines with neighboring grids. The velocity field in a wellblock is produced based on a grid-less virtual boundary element method, where streamlines are numerically traced using the fourth-order Runge-Kutta (RK4) method. The local streamline system is then connected with the global streamline system which is produced by Pollock&rsquo;s algorithm. Finally, the reactive transport equation will be solved along these streamlines. </p><p> The presented algorithm for solving near-wellbore streamlines is verified by both a commercial finite element simulator and Pollock-algorithm-based 3D streamline simulator. A series of computational cases of reactive transport simulation are studied to demonstrate the applicability, accuracy, and efficiency of the proposed method. Velocity field, time-of-flight (TOF), streamline pattern, and concentration distribution produced by different approaches are analyzed. Results show that the presented method can accurately perform near-wellbore streamline simulations in a time-efficient manner. The algorithm can be directly applied to one grid containing multiple wells or off-center wells, as well. Furthermore, assuming streamlines are evenly launched from the gridblock boundary or ignoring transport in the wellblock is not always reasonable, and may lead to a significant error. </p><p> This study provides a simple and grid-free solution, but is capable of capturing the flow field near the wellbore with significant accuracy and computational efficiency. The method is promising for streamline-based reservoir simulation with time-sensitive transport, and other simulations requiring an accurate assessment of interactions between wells in one particular gridblock.</p><p>

<p> The vertical and horizontal mechanical properties of a VTI medium can be obtained from five stiffness coefficients (C₃₃, C₄₄, C₆₆, C₁₃, and C₁₂) using velocities at different angles and density measurements. However, when using well log data for vertical wells, only three out of the five elastic constants can be calculated. The sonic tool cannot measure C₁₃ and C₁₂; thus, different empirical models have been proposed to determine them, making assumptions that do not provide completely accurate results. In this paper, a new empirical model is introduced to obtain the stiffness coefficients. Datasets of dynamic core measurements of shales from different parts of the world are compiled and later, analyzed. The method was based on establishing correlations for the stiffness coefficients, both for each formation and for all formations put together. There were two sets of correlations&mdash;those with C₃₃ as the dependent variable, and those with C₄₄ as the dependent variable. M-ANNIE assumptions were also obtained. Because Stoneley slowness is difficult to measure and can cause errors in the calculations, it was not used. </p><p> Finally, isotropic and VTI minimum horizontal stresses are calculated and compared using well log data from the Bakken formation. VTI minimum horizontal stress calculations used the M-ANNIE model and the correlations determined for the Bakken formation core data. Generally, the new model provides results similar to M-ANNIE predictions, and better results than the isotropic and ANNIE models. Although the proposed method produces results similar to those of the M-ANNIE model, which is widely used as a reference model throughout the industry, the proposed method is different in that it can be used under a different set of circumstances when some inputs are available, and others are not. This method reduces the underestimation of minimum horizontal stress made by the isotropic and ANNIE models as well.</p><p>

<p> The shale boom has introduced new technology into the oil and gas industry. It has created a new source of energy and has helped create a surplus in volume. With the recent decrease in oil prices, engineers must be creative and again use technology to make wells more productive. This study is done to observe the role of fracture conductivity in a hydraulically fractured well using a commercially available software. This will allow for engineers to improve fracking techniques. From this, it helps to consider the reliability of simulation software. </p><p> A typical well in the Eagle Ford Shale formation was selected to model. Completion data was gathered for a horizontal well that had seventeen fracture stages. In the simulation models, the fracture fluid volume was held constant to honor the original well production data. The fracture conductivity was studied using two different methods. The first involved observing one single fracture using different combinations of fracture conductivity throughout the fracture length. The second method incorporated the entire well and observed interactions between fractures with different altered fracture conductivities. Only one fracture was used per stage based off an existing fracture model. Production data with respect to time was analyzed and compared to real time field data. </p><p> After production results were analyzed, it can be seen that the models give a reliable representation of a horizontal well in the Eagle Ford Shale. When viewing the results of the single fracture stage, the cumulative productions are very similar, and when comparing the entire well with seventeen stages, the cumulative production begins to change slightly from model to model. Still, the difference in models does not merit an endorsement of a new completion technique for fracture conductivity. The results indicate that infinite acting flow takes over because of the low permeability reservoir. </p><p>

<p> A bull heading operation is a static non-circulating well control method used to regain integrity of the wellbore. This method is used when there is no drill/tubing string in the wellbore to circulate the kick out of the wellbore. A bull-heading operation requires the use of hydraulic force to overcome the static shut-in pressures of the reservoirs and provide a differential pressure. This differential pressure is required to overcome wellbore and formation friction forces and drive the kill fluid, at a desired flow rate, down the wellbore. </p><p> In tight conventional reservoirs it is very difficult to accurately simulate the requirements needed to conduct a Bullhead operation. Is it critical to properly estimate the maximum anticipated surface pressure expected during any well control operation. If not done accurately, the equipment used during this operation can surpass its limitations, leading to compromising the integrity of the equipment. The key component to estimate is the differential pressure required to force the oil back into the reservoir at a required kill fluid velocity. A specific kill fluid velocity is required to hydraulically kill the well by preventing the reservoir fluids from u tubing with the heavier kill fluid. Bullhead simulations don&rsquo;t focus on injection pressure modeling, which is believed the reason why the required differential pressure is being underestimated in deep-water applications. The goals of this project is to create a reservoir model, analyze the three-dimensional fluid flow that will occur during a bull heading operation, and conduct a sensitivity analysis on the parameters that affect the injection pressure. This will allow us to accurately estimate the injection pressure required to force the oil back into the reservoir and also determine what impact certain reservoir properties have on injection pressure.</p><p>

<p>Enhanced Oil Recovery (EOR) is regarded as new and effective technology to produce oil and gas in recent years. EOR technology has been widely used as a method of enhancing remaining oil to several oil fields? production. This experiment provides detailed analysis and approves the effectiveness of algae polymer. It also gives some suggestions, which were based on information obtained from other researches for future test.

<p>Modern hydraulic fracturing designs assume that drilled formations are both isotropic and homogeneous, and fractures are linear and symmetrical. However, unconventional resources are often obtained from formations that are both anisotropic and heterogeneous, resulting in complex fracture behavior. The objective of this study is to evaluate fracture behavior based on the influence of anisotropy and water saturation. Isotropic and homogeneous Austin Chalk, Berea Sister Gray Sandstone, and Silurian Dolomite, laminated anisotropic and heterogeneous Parker Sandstone, Nugget Sandstone, and Winterset Limestone Carbonate, and fully anisotropic and heterogeneous Edwards Brown Carbonate cores were ordered for testing. Brazilian discs were cut according the ISRM and ASTM standards, and prepared as dry, brine saturated, and fresh water saturated samples. All samples were fractured by the Brazilian test, and laminated anisotropic samples were tested at various loading angles (0?, 15?, 30?, 45?, 90?). Tensile strengths were calculated using the peak load of the primary fracture of each sample, and the fractures were observed for geometrical trends. Additionally, the strain development of each fracture was analyzed through the application of Digital Image Correlation (DIC) software. The results determined that anisotropy and saturation can decrease the tensile strength of a formation. The fracture geometries were influenced by planes of anisotropic lamination, and fully anisotropic rocks produced winding, erratic fractures. DIC allowed for closer 101 examination of fracture development, and identified that saturation can cause failure along lamination planes subjected to less than the maximum, load induced stress. This research can be utilized to improve the hydraulic fracturing design models to optimize formation fractures, and increase revenue for the oil and gas industry.

<p> Hydrocarbon recovery rates within the Niobrara Shale are estimated as low as 2&ndash;8%. These recovery rates are controlled by the ability to effectively hydraulic fracture stimulate the reservoir using multistage horizontal wells. Subsequent to any mechanical issues that affect production from lateral wells, the variability in production performance and reserve recovery along multistage lateral shale wells is controlled by the reservoir heterogeneity and its consequent effect on hydraulic fracture stimulation efficiency. Using identical stimulation designs on a number of wells that are as close as 600ft apart can yield variable production and recovery rates due to inefficiencies in hydraulic fracture stimulation that result from the variability in elastic rock properties and in-situ stress conditions. </p><p> As a means for examining the effect of the geological heterogeneity on hydraulic fracturing and production within the Niobrara Formation, a 3D geomechanical model is derived using geostatistical methods and volumetric calculations as an input to hydraulic fracture stimulation. The 3D geomechanical model incorporates the faults, lithological facies changes and lateral variation in reservoir properties and elastic rock properties that best represent the static reservoir conditions pre-hydraulic fracturing. Using a 3D numerical reservoir simulator, a hydraulic fracture predictive model is generated and calibrated to field diagnostic measurements (DFIT) and observations (microseismic and 4D/9C multicomponent time-lapse seismic). By incorporating the geological heterogeneity into the 3D hydraulic fracture simulation, a more representative response is generated that demonstrate the variability in hydraulic fracturing efficiency along the lateral wells that will inevitability influence production performance. </p><p> Based on the 3D hydraulic fracture simulation results, integrated with microseismic observations and 4D/9C time-lapse seismic analysis (post-hydraulic fracturing &amp; post production), the variability in production performance within the Niobrara Shale wells is shown to significantly be affected by the lateral variability in reservoir quality, well and stage positioning relative to the target interval, and the relative completion efficiency. The variation in reservoir properties, faults, rock strength parameters, and in-situ stress conditions are shown to influence and control the hydraulic fracturing geometry and stimulation efficiency resulting in complex and isolated induced fracture geometries to form within the reservoir. This consequently impacts the effective drainage areas, production performance and recovery rates from inefficiently stimulated horizontal wells. </p><p> The 3D simulation results coupled with the 4D seismic interpretations illustrate that there is still room for improvement to be made in optimizing well spacing and hydraulic fracturing efficiency within the Niobrara Formation. Integrated analysis show that the Niobrara reservoir is not uniformly stimulated. The vertical and lateral variability in rock properties control the hydraulic fracturing efficiency and geometry. Better production is also correlated to higher fracture conductivity. 4D seismic interpretation is also shown to be essential for the validation and calibration hydraulic fracture simulation models. The hydraulic fracture modeling also demonstrations that there is bypassed pay in the Niobrara B chalk resulting from initial Niobrara C chalk stimulation treatments. Forward modeling also shows that low pressure intervals within the Niobrara reservoir influence hydraulic fracturing and infill drilling during field development.</p><p>

<p> In this study, several efficient and accurate mathematical models and numerical solutions to unconventional reservoir development problems are developed. The first is the three-dimensional embedded discrete fracture method (3D-EDFM), which is able to simulate fluid flow with multiple 3D hydraulic fractures with arbitrary strike and dip angles, shapes, curvatures, conductivities and connections. The second is a multi-porosity and multi-physics fluid flow model, which can capture gas flow behaviors in shales, which is complicated by highly heterogeneous and hierarchical rock structures (ranging from organic nanopores, inorganic nanopores, less permeable micro-fractures, more permeable macro-fractures to hydraulic fractures). The third is an iterative numerical approach combining the extended finite element method (X-FEM) and the embedded discrete fracture method (EDFM), which is developed for simulating the fluid-driven fracture propagation process in porous media. </p><p> Physical explanations and mathematical equations behind these mathematical models and numerical approaches are described in detail. Their advantages over alternative numerical methods are discussed. These numerical methods are incorporated into an in-house program. A series of synthetic but realistic cases are simulated. Simulated results reveal physical understandings qualitatively and match with available analytical solutions quantitatively. These novel mathematical models and computational solutions provide numerical approaches to understand complicated physical phenomena in developing unconventional reservoirs, thus they help in the better management of unconventional reservoirs. </p><p>

Thesis (Ph. D.)--University of Texas at Austin, 2001. / Vita. Includes bibliographical references. Available also from UMI/Dissertation Abstracts International.