Browsing by Subject "Secondary recovery of oil"
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Item A study of improved recovery by vaporization/condensation process due to elevating temperatures in hydrocarbon reservoirs(Texas Tech University, 1998-05) Jain, Vishok K.A simulation of vaporization/condensation process was conducted to study the effect of the process on the gas enrichment and overall recovery of a low density crude oil. The simulation begins with the identification of the most suitable equation of state model to characterize vaporization/condensation process. This was accomplished by simulating the constant volume depletion test and constant composition expansion test using three equation of state models and comparing the simulation results with the available experimental data. The equation of model, which predicted the constant volume depletion data most accurately, was selected to be used further in the study. The Peng-Robinson equation of state was found to be most accurate in predicting the experimental data. The vaporization/condensation process was characterized by employing a combination of constant volume depletion test simulation and flash calculations using the selected equation of state. The entire characterization of vaporization/condensation process was performed on WinProp, a phase property program. The vaporization/condensation process was found to be feasible as it was resulting in gas enrichment and increase in liquid saturation. These results were much more pronounced when conducted the vaporization/condensation at the high pressure and high vaporization temperature. Therefore, it was concluded that the vaporization/condensation may result in additional recovery if carried out at high reservoir pressure and high vaporization temperature.Item A study of residence time distributions for polyacrylamide solutions flowing through porous media as applied to enhanced oil recovery(Texas Tech University, 1985-05) Martin, Roger IrwinThe overall objective of this research is to develop an accurate modeling of the axisymmetric flow of dilute polyacrylamide polymer solutions through consolidated porous media via a generation of residence time distribution curves.Item Finite difference modeling of oil recovery by waterflooding using horizontal well injectors(Texas Tech University, 1998-12) Faruqi, Sohail ArshedWaterflooding is the most commonly used injection method for secondary recovery of oil reservoirs. The selection of a horizontal well or a vertical well as an injector is an important issue in waterflooding because these two types of wells can behave differently due to their orientation in the reservoir. Horizontal wells, due to their geometry, possess great apparent potential in injection processes because these wells have large contact with the formation as compared to the vertical wells. The performance of vertical well injectors in waterflooding an oil reservoir have been extensively investigated and reported in the literature. The detailed analysis of the performance of horizontal well injectors, on the other hand, is not found in the literature. The objective of this research was to investigate the potential of horizontal well injectors in waterflood operation with the help of a reservoir simulator. A two-phase, black oil model was developed in this research to study the potential of horizontal well injectors in waterflooding. The results showed that vertical to horizontal permeability ratio and formation thickness are the two main factors that can affect the performance of a horizontal well injector as compared to a vertical well injector. As the vertical to horizontal permeability ratio decreases, the advantage of a horizontal well injector over a vertical well injector decreases. This change in the permeability ratio does not have any significant effect on the performance of a vertical well injector. Also, the smaller the formation thickness, the better the performance of the horizontal well injectors.Item Iteratively coupled reservoir simulation for multiphase flow in porous media(2008-05) Lu, Bo, 1979-; Wheeler, Mary F. (Mary Fanett)Fully implicit and IMPES are two primary reservoir simulation schemes that are currently used widely. However, neither of them is sufficiently accurate or ef- ficient, given the increasing size and degree of complexity of highly heterogeneous reservoirs. In this dissertation, an iterative coupling approach is proposed and developed to solve multiphase flow problems targeting the efficient, robust and accurate simulation of the hydrocarbon recovery process. In the iterative coupling approach, the pressure equation is solved implicitly, followed by the saturation equation, which is solved semi-implicitly. These two stages are iteratively coupled at the end of each time step by evaluating material balance, both locally and globally, to check the convergence of each iteration. Additional iterations are conducted, if necessary; otherwise the simulation proceeds to the next time step. Several numerical techniques are incorporated to speed up the program convergence and cut down the number of iterations per time step, thus greatly improving iterative model performance. The iterative air-water model, the oil-water model, and the black oil model are all developed in this work. Several numerical examples have been tested using the iterative approach, the fully implicit method, and the IMPES method. Results show that with the iterative method, about 20%-40% of simulation time is saved when compared to the fully implicit method with similar accuracy. As compared to the IMPES method, the iterative method shows better stability, allowing larger time steps in simulation. The iterative method also produces better mass balance than IMPES over the same time. The iterative method is developed for parallel implementation, and several test cases have been run on parallel clusters with large numbers of processors. Good parallel scalability enables the iterative method to solve large problems with millions of elements and highly heterogeneous reservoir properties. Linear solvers take the greatest portion of CPU time in reservoir simulations. This dissertation investigates advanced linear solvers for high performance computers (HPC) for reservoir simulation. Their performance is compared and discussed.Item Measurement and modeling of multiscale flow and transport through large-vug Cretaceous carbonates(2008-08) Nair, Narayan Gopinathan, 1980-; Bryant, Steven L.; Jennings, James W.Many of the world's oil fields and aquifers are found in carbonate strata. Some of these formations contain vugs or cavities several centimeters in size. Flow of fluids through such rocks depends strongly upon the spatial distribution and connectivity of the vugs. Enhanced oil recovery processes such as enriched gas drives and groundwater remediation efforts like soil venting operations depend on the amount of hydrodynamic dispersion of such rocks. Selecting a representative scale to measure permeability and dispersivity in such rocks can be crucial because the connected vug lengths can be longer than typical core diameters. Large touching vug (centimeter-scale), Cretaceous carbonate rocks from an exposed rudist (caprinid) reef buildup at the Pipe Creek Outcrop in Central Texas were studied at three different scales. Single-phase airflow and gas-tracer experiments were conducted on 2.5 in. diameter by 5 in. long cores (core-scale) and 5- to 10-ft-radius well tests (field-scale). Zhang et al. (2005) studied a 10 in. diameter by 14 in. high sample (bench-scale). Vertical permeability in the bench-scale varied from 100 darcies to 10 md and in the core-scale averaged 2.5 darcies. The field-scale permeability was estimated to be 500 md from steady state airflow and pressure transient tests. In the bench and core scales a connected path of vugs dominates flow and tracer concentration breakthrough profile. Tracer transport showed immediate breakthrough times and a long tail in the tracer concentrations characterized by multiple plateaus in concentrations. Neither flow nor tracer transport can be explained at these scales by the standard continuum equations (Darcy’s law or 1D convection dispersion equation). However, interpreting field-scale measurements with standard continuum equations suggested that a strongly connected path of vugs did not extend past a few feet. In particular, the tracer experiment in the field scale can be modeled accurately using an equivalent homogeneous porous medium with a dispersivity of 0.5 ft. In our measurements, permeability decreased with scale, while vug connectivity and multi-scale effects associated with vug connectivity decreased with increasing scale. We concluded that approximately 5 ft could be considered the representative scale for the large-touching-vug carbonate rocks at the Pipe Creek Outcrop. The major contribution of this research is the introduction of an integrated, multi-scale, experimental approach to understanding fluid flow in carbonate rocks with interconnected networks of vugs too large to be adequately characterized in core samples alone.Item Modeling the mobilization of connate water while injecting water to displace oil(Texas Tech University, 1998-12) Husband, Michael EarnestThe presence of connate water in an oil reservoir can significantly affect oil recovery. The mobility of the connate water can have adverse effects on the success of injected water additives designed to increase oil recovery. This research is an effort to characterize the mechanisms involved in the displacement process of connate water. This dissertation is the first attempt to characterize connate water mechanisms by creating a set of relative permeability curves to describe the injected water displacing connate water in a system that contains oil, injected water and connate water. The work in the dissertation is a detailed analysis of the displacement test. Buckley and Leverett developed the theory and equation to predict the mobility (fractional flow) of oil and water from oil and water relative permeability curves. The Buckley/Leverett equation is the basis of the unsteady-state method of creating relative permeability curves from displacement tests of immiscible fluids. This dissertation presents a modification of the Buckley/Leverett theory to characterize the miscible displacement of connate water by injected water. Relative permeability curves for connate and injected water were created from fractional flow values determined by using the expanded Buckley/Leverett theory. The relative permeability curves describe the mobility of connate water as the water saturation increases due to water injection. The combined set of permeability values can be used in a four-component computer simulation routine to predict how the oil recovery was influenced by connate water mobility in a field scale enhanced oil recovery program.Item Simulation of a miscible carbon dioxide flood using a trapped oil function(Texas Tech University, 1989-05) Culpepper, Patricia BiegaNot availableItem Sweep efficiency for solvent injection into heavy oil reservoirs at grain-scale displacement of extremely viscous fluid(2007-12) Taghizadeh Dizaj Cheraghi, Okhtay, 1974-; Sepehrnoori, Kamy, 1951-; Bryant, Steven L.The movement of low viscosity fluid through a porous medium containing extremely viscous fluid is emerging as an important phenomenon in several petroleum engineering applications. These include the recovery of heavy oil by solvent injection, the preferential reduction of water flow using polymer gels, and the enhancement of acid fracturing treatments. The displacement of one fluid from a porous medium by a second, immiscible fluid has been extensively studied in two cases: when capillary forces are dominant, and when viscous forces are comparable to capillary forces. This dissertation research examines a third case: when viscous forces are dominant. The viscosity of the fluid initially present in the porous medium is four or more orders of magnitude greater than the viscosity of the displacing fluid. Consequently, the displacement through an individual pore will be dictated by the hydrodynamic forces required to move the high viscosity fluid. However, very little is known about grain-scale behavior of such displacements. The research will develop a mathematical model of the viscosity-dominated displacement in a network of conduits. By neglecting pressure drop within the low viscosity fluid, the model will treat the displacement as a moving boundary problem. The high viscosity fluid will be assumed Newtonian and will move in response to the pressure gradient imposed via the low viscosity fluid. The movement can be treated as pseudo-steady state flow of the highviscosity fluid. The flow field will be updated whenever the low viscosity fluid advances into a pore previously occupied by high-viscosity fluid. Swept volume will be calculated in each run for comparison and further investigation. We will use classical methods for direct and iterative solutions of large, sparse linear systems to compute these steady states. Key practical insights to be obtained from the model are the nature of the displacement and effects of geometry and hydraulic conductivities on the sweep efficiency. The model will form the basis for examining additional physical processes, notably mass transfer between fluids, and the possibility that fingering of the low viscosity fluid occurs within individual pore throats.Item Theoretical and experimental study of foam for enhanced oil recovery and acid diversion(2003) Xu, Qiang; Rossen, William Richard.This dissertation comprises three studies of foam in porous media. The first study is a theoretical model for apparent viscosity of foam in porous media. This represents the first dynamic model for the movement of bubbles through constricted tubes in 2D, accounting for the drag on lamellae (soap films) along pore walls and the capillary forces that govern bubble shape in constricted tubes. At low velocities behavior fits earlier quasi-static and approximate models. At higher velocities, behavior is complex; for instance, pressure gradient can decrease with increasing bubble velocity. This work could provide a component to a fully mechanistic foam simulator. The second study is an experimental investigation of SAG foam processes for enhanced oil recovery, where gas and surfactant solution are injected in alternating slugs. Experimental fractional-flow curves are presented for two surfactant formulations in Berea sandstone, with no oil present. Results are then scaled-up using fractional-flow theory to a hypothetical 1D field-scale application. In one case the data suggest an abrupt jump from a strong-foam fractional-flow curve to a weaker-foam curve, as has been reported elsewhere. In both cases the data suggest successful mobility control on the field scale. The third study is an experimental investigation of post-foam liquid injection, which is the key to the success of foam-acid diversion for matrix-acid well stimulation. Results indicate that with high foam quality pressure gradient can be higher during liquid injection than during foam injection; this may require reconsideration of the optimal foam quality for foam-acid diversion. It appears that the water relative-permeability function obtained during foam injection also applies to liquid injection after foam, until trapped gas begins to dissolve into injected liquid. The extent of gas trapping and liquid mobility after foam varied with foam quality here, which means earlier models that exclude this effect may need to be revised. In both experimental studies, pressure gradient was monitored along the core and liquid saturation was determined by weighing the core continuously during the experiment. Strengths and shortcomings of this technique for determining water saturation are discussed, along with suggestions for improving the technique.