<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.

No description available.

The dynamic nature of coalbed methane reservoir permeability makes the continuous modeling of the flow process difficult. Knowledge of conventional reservoir modeling is of little value because the gas storage and flow mechanisms in coal are remarkably different. Field observations suggest that the gas productivity does not decline with time as expected. An increasing permeability is a possible explanation. This laboratory study is aimed at measuring the volumetric changes in coal matrix resulting from gas desorption, its impact on coal porosity and permeability, and an estimate of the stage when the effect is significant. Results using cylindrical samples of coal suggest that coal matrix shrinks with desorption of gas. The shrinkage is linearly proportional to the quantity of gas desorbed. Using the measured changes in matrix volume, variations in total and cleat porosity were estimated and found to increase significantly with desorption. These changes should, therefore, be used as input when simulating long-term gas production.

The objectives of this investigation were to measure the effect of the various factors that contribute to differential-pressure pipe sticking and to utilize this information in the development of a procedure to select casing setting depths The investigation differs from other investigations in that it (1) evaluates several areas in the Gulf of Mexico, not just one specific area; (2) evaluates both deviated and straight holes; (3) analyzes both wells that experience and did not experience sticking problems; and (4) analyzes the factors that may contribute to differential-pressure pipe sticking The results of this investigation normalized all factors that contribute to differential-pressure pipe sticking except differential pressure. It was concluded that the average differential pressure for those wells that experienced sticking problems and those that did not were not similar. It was also concluded that, of the wells that experienced sticking problems, more than 99 percent of them were stuck at pressures greater than 1,298 pounds per square inch The major application of this investigation is a procedure to select casing setting depths based on the ability to withstand a design-size kick and the potential of pipe sticking off-bottom / acase@tulane.edu

This dissertation documents research results from a series of field experiments and analyses used to test interpretive models for investigating the role of fractures in fluid flow through unsaturated, fractured tuffs. It summarizes the experimental design of single- and cross-hole pneumatic injection tests, including borehole configuration and testing schedules, data collection system, interpretive models developed and tested, data, and conclusions. Single-hole tests were interpreted by Guzman et al. (1996) by means of steady-state analysis to obtain permeability values based solely on late pressure data. This dissertation and Illman et al. (1998) employ pressure and pressure-derivative type-curves to analyze transient data. Air permeabilities determined from transient analyses agree well with those derived from steady-state analyses. Cross-hole pneumatic tests were analyzed by means of a graphical matching procedure using newly-developed pressure and pressure-derivative type-curves. Analyses of pressure data from individual monitoring intervals using these new type-curves, under the assumption that the rock acts as a uniform and isotropic fractured porous continuum, yield results that are comparable with parameters obtained from a numerical inverse procedure described in Illman et al. (1998). The results include information about pneumatic connections between the injection and monitoring intervals, corresponding directional air permeabilities, and air-filled porosities. Together with the results of earlier site investigations, single- and cross-hole test analyses reveal that at the Apache Leap Research Site in central Arizona: (1) the pneumatic pressure behavior of fractured tuff is amenable to analysis by methods that treat the rock as a continuum on scales ranging from meters to tens of meters; (2) this continuum is representative primarily, but not exclusively, of interconnected fractures; (3) its pneumatic properties vary strongly with location, direction and scale, in particular, the mean of pneumatic permeabilities increases, and their variance decreases with scale; (4) this scale effect is most probably due to the presence in the rock of various size fractures that are interconnected on a variety of scales; and (5) given a sufficiently large sample of spatially varying pneumatic rock properties on a given scale of measurement, these properties are amenable to analysis by geostatistical methods, which treat them as correlated random fields defined over a continuum.

Transmission of down-hole measurements to the surface while the oil well is being drilled (logging while drilling-LWD-telemetry) is the key to the efficient and successful recovery of hydrocarbon resources. The most promising method of telemetry uses compressional acoustic waves to transmit data along the drillstring. In this technique, telemetry signals are encoded as acoustic wave pulses that propagate through the drillstring and are subsequently received and converted back to electric signals for data recovery at the surface receiver. Based on the analysis of the wave propagation properties in the drillstring, I propose and design an acoustic orthogonal frequency division multiplexing (OFDM) transmission scheme to efficiently communicate through the channel. To prove the feasibility of the proposed communication technique, numerous field tests were successfully designed and implemented in various drilling oil rigs. Then I characterize the performance of the oil well telemetry system and propose a joint source-channel coding approach wherein the end-to-end distortion in reconstructing telemetry signals at the surface receiver is directly minimized. I show that the acoustic OFDM technique enables simple implementation of the joint source-channel coding design criterion and present the methodology for optimizing different transmission scheme components. Realistic LWD acoustic telemetry design examples demonstrate that the optimal design results in significant gains in system performance and throughput as compared to standard design approaches.