<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> Integrating Techlog, Petrel, Eclipse, and COMSOL is a game changer and led to a better understanding of a very complex undercompacted and overpressurized sand in Block 276. Different reservoir simulation sensitivity runs on P1-sand indicated that putting a new well in block (2,34) under pure depletion will yield the highest incremental oil recovery of about 38%. The sensitivity runs included dumpfloods, waterfloods, and artificial lift. COMSOL has also shown that formation overlying the salt dome is hotter than other portions of the reservoir and that planning a new well on the western flank of the accumulation was the right decision. COMSOL has also shown that overpressurization is driven by undercompaction but that heat conduction from the dome and underlying diapirs affected pore pressure by 3 to 15%.</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.

This report adapts the application of a methodology known as Analytic Hierarchy Process (AHP) to upstream Exploration & Production (E&P) project evaluations for the oil and gas industry. The method can be used to simplify the process of decision making, specifically when several parameters or variables—mostly uncertainties or risk variables—are being considered for different investment options. This method has been used in a large number of applications in several research areas where evaluation and decision making is a key issue. It simplifies the considerations that the evaluators must be aware of to assign probability or certainty factors to the parameters by using a relative intensity scale. We apply the method to the quantification of the risk involved in typical upstream projects. Although a decision as large as investment in oil and gas projects can not be based solely on risk factors, it is true that the risk attitude of the investor will ultimately play a significant role. This method gathers all the possible factors that can affect a project at any stage and provides the user with a single number; it condenses all the considerations and preferences of the investor or decision maker and ranks the investment alternatives from a risk point of view. A typical problem confronted with E&P project assessment (as well as in many other industries) is that the criteria selected may be measured on different scales, such as dollar value, stock-tank barrels, standard cubic feet, units of area, and so on. Some might even be intangible for which no scales exist, such as financial environment, management problems, or social unsteadiness. Measures on different scales, obviously, can not be directly combined, and this is part of what makes an integral assessment of any project such a difficulty. It is up to the decision maker to put all these evaluations—which may be still in different or subjective scales—on an overall comparative basis. This is where the AHP becomes useful, by gathering criteria of different natures and dimensions, and putting them all together on a single scale, which is derived from the decisions maker’s preferences and risk attitude.

This report adapts the application of a methodology known as Analytic Hierarchy Process (AHP) to upstream Exploration & Production (E&P) project evaluations for the oil and gas industry. The method can be used to simplify the process of decision making, specifically when several parameters or variables—mostly uncertainties or risk variables—are being considered for different investment options. This method has been used in a large number of applications in several research areas where evaluation and decision making is a key issue. It simplifies the considerations that the evaluators must be aware of to assign probability or certainty factors to the parameters by using a relative intensity scale. We apply the method to the quantification of the risk involved in typical upstream projects. Although a decision as large as investment in oil and gas projects can not be based solely on risk factors, it is true that the risk attitude of the investor will ultimately play a significant role. This method gathers all the possible factors that can affect a project at any stage and provides the user with a single number; it condenses all the considerations and preferences of the investor or decision maker and ranks the investment alternatives from a risk point of view. A typical problem confronted with E&P project assessment (as well as in many other industries) is that the criteria selected may be measured on different scales, such as dollar value, stock-tank barrels, standard cubic feet, units of area, and so on. Some might even be intangible for which no scales exist, such as financial environment, management problems, or social unsteadiness. Measures on different scales, obviously, can not be directly combined, and this is part of what makes an integral assessment of any project such a difficulty. It is up to the decision maker to put all these evaluations—which may be still in different or subjective scales—on an overall comparative basis. This is where the AHP becomes useful, by gathering criteria of different natures and dimensions, and putting them all together on a single scale, which is derived from the decisions maker’s preferences and risk attitude.

Shale is often the most difficult of all formations to maintain a stable wellbore in when drillincr ::> for oil and gas. Time and money spent overcoming this problem during drilling, together with overall reduced profit margins. has led the oil industry to devote considerable time and effort to solve the problem of unstable boreholes in shales. It has long been established that the moisture adsorption (or desorption) of shale rocks can be controlled by the salinity of drilling fluid. When compacted shale (under constant compaction stress) adsorbs moisture, its total volume increases and swelling strains develop. Developed swelling strains then become an integral part of the effective radial stress acting on the shale formation contributing to borehole failure. A mathematical model has been developed for predicting the swelling behaviour of shale when placed in contact with water under moderate pressures and the effect of the swelling on borehole (in)stability. The model is based on thermodynamic theory which suggests that fluid movement into or out of a shale is driven by an imbalance in the partial molar free energy of the shale and the contacting fluid. Conversion of the free energy of each system (fluid and shale) into "total swelling pressure" made it possible to model transient pressures and strains generated in shale. The analytical solution of the radial diffusivity equation is reduced to a simpler form for the model. The model was validated using equipment and experimental techniques which allow continuous monitoring of shale swelling as function of time and distance from the wetting end. It was found that increasing the compaction stress acting on the shale reduced the rate of swelling, and increasing the hydraulic pressure of the fluid on the shale's wetted surface increased the rate of swelling. This behaviour was adequately described by the model which therefore represents a new method for predicting shale swelling as function of time and radial distance under different environments. Swelling strains are then used to predict related changes in shale mechanical properties (failure criteria) and well (in)stability. Several well-site index tests have been developed to study shale-drilling fluid interaction at wellsite. These index tests can provide input data for the mathematical model. Drilling fluids can be screened for their ability to control shale swelling, thus minimising the risk of well bore instability.

Thesis (Ph.D.)--University of Tulsa, 1994. / Includes bibliographical references (leaves 203-210).