Browsing by Subject "Oil wells"
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Item Dynamic analysis of jarring process by finite-difference method(Texas Tech University, 1988-12) Chu, LifuThe mathematical model of the jarring process consists of three Interconnected sub-models. They are described In detail. Including the Initial conditions, boundary conditions and Interconnection conditions. This model resulted In three wave equations which ore too complex to be solved analytically. Therefore, finite difference methods are used to solve them. The finite element discretization, time step choice and stability are discussed. Also a brief description of the computer programs used to solve these equations Is presented.Item The impact of shale properties on wellbore stability(2005) Zhang, Jianguo; Chenevert, Martin E.; Sharma, Mukul M.Item Investigation of an advanced technique to select an optimal inhibition and removal method of paraffin deposition in oil wells(Texas Tech University, 2001-08) Baruah, Bikram M.From the very beginning of the business of hydrocarbon exploitation, the problem of paraffin deposition was encountered with varying degrees. With oil exploitation expanding into exotic frontiers like deep-water and the Arctic Circle, wax deposition became a greater challenge for the operators. Various mechanical, thermal and chemical methods are used to remove and prevent wax deposition. However, it is often difficult to select the most effective and economic remedial measure for a given situation. Due to uniqueness of every crude, there is no single technique that is most effective for all types of crude oils. The main objective of this thesis project is to explore the feasibilities of using computer-based consulting systems, commonly known as expert systems, to select the best remedial measure of wax deposition in a given situation. Extensive literature survey was carried out to understand and collect information on the phenomena of wax deposition and removal/prevention techniques. A separate survey was conducted to understand expert systems in general and also to find out the criteria and resources required for building one. Then a feasibility study of building an envisioned computer system was conducted. Steps were also taken to initiate the building of an expert system.Item Simulation and design of energized hydraulic fractures(2009-08) Friehauf, Kyle Eugene; Sharma, Mukul M.Hydraulic fracturing is essential for producing gas and oil at an economic rate from low permeability sands. Most fracturing treatments use water and polymers with a gelling agent as a fracturing fluid. The water is held in the small pore spaces by capillary pressure and is not recovered when drawdown pressures are low. The un-recovered water leaves a water saturated zone around the fracture face that stops the flow of gas into the fracture. This is a particularly acute problem in low permeability formations where capillary pressures are high. Depletion (lower reservoir pressures) causes a limitation on the drawdown pressure that can be applied. A hydraulic fracturing process can be energized by the addition of a compressible, sometimes soluble, gas phase into the treatment fluid. When the well is produced, the energized fluid expands and gas comes out of solution. Energizing the fluid creates high gas saturation in the invaded zone, thereby facilitating gas flowback. A new compositional hydraulic fracturing model has been created (EFRAC). This is the first model to include changes in composition, temperature, and phase behavior of the fluid inside the fracture. An equation of state is used to evaluate the phase behavior of the fluid. These compositional effects are coupled with the fluid rheology, proppant transport, and mechanics of fracture growth to create a general model for fracture creation when energized fluids are used. In addition to the fracture propagation model, we have also introduced another new model for hydraulically fractured well productivity. This is the first and only model that takes into account both finite fracture conductivity and damage in the invaded zone in a simple analytical way. EFRAC was successfully used to simulate several fracture treatments in a gas field in South Texas. Based on production estimates, energized fluids may be required when drawdown pressures are smaller than the capillary forces in the formation. For this field, the minimum CO2 gas quality (volume % of gas) recommended is 30% for moderate differences between fracture and reservoir pressures (2900 psi reservoir, 5300 psi fracture). The minimum quality is reduced to 20% when the difference between pressures is larger, resulting in additional gas expansion in the invaded zone. Inlet fluid temperature, flowrate, and base viscosity did not have a large impact on fracture production. Finally, every stage of the fracturing treatment should be energized with a gas component to ensure high gas saturation in the invaded zone. A second, more general, sensitivity study was conducted. Simulations show that CO2 outperforms N2 as a fluid component because it has higher solubility in water at fracturing temperatures and pressures. In fact, all gas components with higher solubility in water will increase the fluid’s ability to reduce damage in the invaded zone. Adding methanol to the fracturing solution can increase the solubility of CO2. N2 should only be used if the gas leaks-off either during the creation of the fracture or during closure, resulting in gas going into the invaded zone. Experimental data is needed to determine if the gas phase leaks-off during the creation of the fracture. Simulations show that the bubbles in a fluid traveling across the face of a porous medium are not likely to attach to the surface of the rock, the filter cake, or penetrate far into the porous medium. In summary, this research has created the first compositional fracturing simulator, a useful tool to aid in energized fracture design. We have made several important and original conclusions about the best practices when using energized fluids in tight gas sands. The models and tools presented here may be used in the future to predict behavior of any multi-phase or multi-component fracturing fluid system.Item A study of wellbore stability in shales including poroelastic, chemical, and thermal effects(2001) Chen, Guizhong, 1968-; Chenevert, Martin E.; Olson, Jon E.Shale is always a troublesome rock during oil and gas drilling operations. Shale (in)stability has been of great concern in the oil industry for decades. It has also been a costly problem and has perplexed the industry for many years. A better understanding of the wellbore stability mechanism in shales is imperative. The object of this study is to develop a comprehensive model to deal with borehole instability problems in shales. Wellbore stability problems are caused by changes in near wellbore pore pressure and rock stresses. The excess of rock effective stresses over the rock strength can cause collapse (shear) or breakdown (tensile) failure of the drilled formation. This imbalance between the rock stress and rock strength always happens when the in-situ rock is drilled out and is replaced by the drilling fluid. Pore pressure alterations due to osmotic effects are a function of the water activity in the drilling fluid and the membrane efficiency of the shale. In this work, thermo-mechanical stresses coupled with the osmotic contributions are used to compute conditions under which the wellbore becomes unstable. The osmotic contribution is added to the hydraulic potential to form the net driving force of the fluid flow. Changes in pore pressure have been observed in shale experiments. An alteration of the shale strength was also observed when shales are exposed to different drilling fluids. It is necessary to consider shale strength alterations when inspecting the wellbore stability status and determining critical mud weights. Thermal diffusion inside the drilled formation induces additional pore pressure and rock stress changes and consequently affects shale stability. Thermal effects are important because thermal diffusion into shale formations occurs more quickly than hydraulic diffusion and thereby dominates during early times. Rock temperature and pore pressure can be partially decoupled for shale formations. The partially decoupled problem can be solved analytically under appropriate inner and boundary conditions. The analytical solutions are consistent with the finite-difference solution to the coupled problem. The decoupled temperature and pore pressure variables are programmed to calculate rock stresses and wellbore failure status. User-friendly input and output interfaces are developed in order to implement this model in the field. This model can also be applied to other petroleum rocks like sandstones.Item Temperature prediction model for a producing horizontal well(2006) Dawkrajai, Pinan; Lake, Larry W.Item The use of capacitance-resistance models to optimize injection allocation and well location in water floods(2009-08) Weber, Daniel Brent; Edgar, Thomas F.; Lake, Larry W.Reservoir management strategies traditionally attempt to combine and balance complex geophysical, petrophysical, thermodynamic and economic factors to determine an optimal method to recover hydrocarbons from a given reservoir. Reservoir simulators have traditionally been too large and run times too long to allow for rigorous solution in conjunction with an optimization algorithm. It has also proven very difficult to marry an optimizer with the large set of nonlinear partial differential equations required for accurate reservoir simulation. A simple capacitance-resistance model (CRM) that characterizes the connectivity between injection and production wells can determine an injection scheme maximizes the value of the reservoir asset. Model parameters are identified using linear and nonlinear regression. The model is then used together with a nonlinear optimization algorithm to compute a set of future injection rates which maximize discounted net profit. This research demonstrates that this simple dynamic model provides an excellent match to historic data. Based on three case studies examining actual reservoirs, the optimal injection schemes based on the capacitance-resistive model yield a predicted increase in hydrocarbon recovery of up to 60% over the extrapolated exponential historic decline. An advantage of using a simple model is its ability to describe large reservoirs in a straightforward way with computation times that are short to moderate. However, applying the CRM to large reservoirs with many wells presents several new challenges. Reservoirs with hundreds of wells have longer production histories – new wells are created, wells are shut in for varying periods of time and production wells are converted to injection wells. Additionally, ensuring that the production data to which the CRM is fit are free from contamination or corruption is important. Several modeling techniques and heuristics are presented that provide a simple, accurate reservoir model that can be used to optimize the value of the reservoir over future time periods. In addition to optimizing reservoir performance by allocating injection, this research presents a few methods that use the CRM to find optimal well locations for new injectors. These algorithms are still in their infancy and represent the best ideas for future research.