Browsing by Subject "Oil production"
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Item Development of a fully implicit, parallel, equation-of-state compositional simulator to model asphaltene precipitation in petroleum reservoirs(2007-12) Fazelipour, Waleed; Pope, G.A.; Sephehrnoori, Kamy, 1951-Asphaltene precipitation is a serious and complex problem in oil recovery that affects all aspects of oil production, processing and transportation. It is very important to predict the asphaltene precipitation during the production process. Many models have been developed to predict the precipitation behavior of asphaltene. In this work we present implementation of asphaltene precipitation model into a fully implicit, three-dimensional, multiphase, multicomponent, parallel, equation-of-state compositional simulator called GPAS, developed at the Center for Petroleum and Geosystems Engineering at The University of Texas at Austin. The primary goal of GPAS, currently under development, is to support realistic, high-resolution reservoir studies with a million or more gridblocks on massively parallel computers. Key requirements for this simulator include the ability to handle multiple physical models, generalized well management, multiple fault blocks, and flexible gridding. GPAS is developed under the framework named IPARS (Integrated Parallel Accurate Reservoir Simulator) and is constructed using a Newton-type formulation. The Peng-Robinson EOS is used for the hydrocarbon phase behavior calculations. The linear solvers from PETSc package (Portable Extensible Toolkit for Scientific Computation) are used for the solution of the underlying linear equations. The framework provides input/output, table lookups, FORTRAN array memory allocation, domain decomposition, and message passing between processors for updating physical properties in massbalance equations in overlapping regions. PETSc handles communications between processors needed for the linear solver. After studying many available models in the literature for asphaltene precipitation, Nghiem's model was chosen for modeling asphaltene precipitation in GPAS. We believe this implementation has led to a more powerful reservoir simulator that can be used to predict asphaltene precipitation by small and large oil companies to help them in the design of complex gas and waterflooding processes on their desktops or a cluster of computers. Nghiem's model is a solid model that treats the precipitating asphaltene as a single component residing in the solid phase while oil and gas phases are modeled with a cubic EOS. Solid models may require many empirical parameters and a large amount of tuning to match experimental data. Since asphaltene precipitation severely reduces both absolute permeability and relative permeability, it is important to simulate the precipitation behavior of asphaltenes during the oil production process. Many models have been developed to predict the onset point and the amount of asphaltene precipitation as well as the change in relative permeability. In this study, physical properties models were also implemented in GPAS to estimate the effect of asphaltene precipitation on permeability in order to calculate the amount of precipitation during oil production. Compositional simulation results with asphaltene precipitation model indicate that asphaltene precipitation may damage the oil production in most cases. A key conclusion of the findings is the ability to predict the deposition of asphaltenes in the reservoir without the need for generating data from expensive downhole samples.Item Modeling Asphaltene Precipitation and Implementation of Group Contribution Equation of State Into Utcomp(1998-08) Qin, Xiangjun; Pope, Gary A.; Sepehrnoori, KamyThe main objective of this research was to improve the accuracy of the UTCOMP simulator for predicting oil production. This work includes two parts. The first part is to simulate the asphaltene precipitation during oil recovery, and the second part is to implement group contribution equation-of-state for the phase equilibrium calculations in reservoir simulations. Asphaltene precipitation is a serious problem in oil recovery, and it may damage the oil production. Many models have been developed to predict the asphaltene precipitation behavior. In this study, Nghiem's model for asphaltene precipitation was selected and implemented into the UTCOMP simulator. In order to simplify the phase equilibrium calculation, a pseudo-three-phase algorithm was used to obtain the amount of precipitation during the production process. The precipitated solid that resides in the reservoir may affect the porosity, permeability and wettability of the reservoir rock. To derive the effect of precipitation on porosity, the precipitated asphaltene was treated as part of the reservoir rock. This assumption makes it possible to compute the absolute permeability using a power-law model. The relative permeability was calculated using a resistance-factor model. However, permeability is a very strong function of pore structure. To relate the effect of asphaltene precipitation on both permeability and relative permeability to pore structure of the reservoir rock, a rock-fabric classification model was implemented into the simulator. This model combines the permeability and relative permeability models using a rock-fabric classification for carbonate reservoir rocks. To further improve the computational efficiency, a simplified algorithm was implemented to compute the amount of asphaltene precipitation. In this algorithm, the equilibrium calculation used to obtain the amount of precipitation was decoupled from the phase equilibrium computation. Simulation results indicate that asphaltene precipitation may damage the oil production in most cases. But if the rock permeability is high and the rock classification number is low, precipitation may actually result in a slight increase in oil production. The results also show that the new simplified algorithm to compute the amount of precipitation was successful in reproducing the coupled results while saving much of the computer time. The second part of this research was to implement the group contribution equation-of-state into the simulator. There were two choices of equations-of-state in the UTCOMP simulator. They were the Peng-Robinson equation-of-state and a modified Redlich-Kwong equation-of-state. However, both equations are not good in representing the phase behavior for mixtures containing polar components such as water or alcohol. In order to improve the accuracy of phase equilibrium, the Wong-Sandler group contribution equation-of-state was selected and implemented into the simulator. The model is a combination of the UNIFAC group contribution method, which is good in computing the activity coefficients for both polar and nonpolar mixtures, and the Peng-Robinson equation-of-state, which is good for phase equilibrium at high pressure. Thus, the group contribution equation-of-state takes advantage of both methods and results in more accurate predictions of phase equilibrium for mixtures containing polar components. This is illustrated for some binary polar mixtures. The applicability of the group contribution equation-of-state extends the capability of the simulator to some special reservoir conditions and problems.Item Modeling chemical EOR processes using IMPEC and fully IMPLICIT reservoir simulators(2009-08) Fathi Najafabadi, Nariman; Delshad, Mojdeh; Sepehrnoori, Kamy, 1951-As easy target reservoirs are depleted around the world, the need for intelligent enhanced oil recovery (EOR) methods increases. The first part of this work is focused on modeling aspects of novel chemical EOR methods for naturally fractured reservoirs (NFR) involving wettability modification towards more water wet conditions. The wettability of preferentially oil wet carbonates can be modified to more water wet conditions using alkali and/or surfactant solutions. This helps the oil production by increasing the rate of spontaneous imbibition of water from fractures into the matrix. This novel method cannot be successfully implemented in the field unless all of the mechanisms involved in this process are fully understood. A wettability alteration model is developed and implemented in the chemical flooding simulator, UTCHEM. A combination of laboratory experimental results and modeling is then used to understand the mechanisms involved in this process and their relative importance. The second part of this work is focused on modeling surfactant/polymer floods using a fully implicit scheme. A fully implicit chemical flooding module with comprehensive oil/brine/surfactant phase behavior is developed and implemented in general purpose adaptive simulator, GPAS. GPAS is a fully implicit, parallel EOS compositional reservoir simulator developed at The University of Texas at Austin. The developed chemical flooding module is then validated against UTCHEM.Item Reservoir characterization of the Cruse Formation, southern Trinidad(2006-05) Winter, Rene Ravi; Steel, R.J.Outcrop study, integrated with core, well, and seismic data has allowed a study of the Cruse Formation of Southern Trinidad in a depositional systems and sequence stratigraphic framework. The Formation represents a 3rd order, Regressive – Transgressive depositional sequence, shallowing from a deep-water, slope dominated setting to a storm-wave influenced outer shelf with deltas, that is overlain by a transgressive shelf that supported retreating fluvially and tidally influenced shorelines. The Formation is capped by a major regional flooding interval, the Lower Forest Clay. Reservoir intervals within the Cruse represent a number of sub-environments that are differentiated by systems tract, ranging from prograding shelf-edge distributary mouth bars, thin-bedded turbidites and basin-floor fans of the Falling Stage and Lowstand Systems Tract (FSST and LST) to storm-influenced delta front and distributary channel fill, bayhead deltas, tidal flats and crevasse splays of the Transgressive and Highstand Systems Tract (TST and HST). Regressive – transgressive units like this repeat and stack 6-7 times in the overall Cruse development. From a depositional systems perspective, reservoirs in the Cruse are superficially similar to reservoirs in the more prolific offshore settings. However, the Cruse Formation records a more fluvially influenced, strongly progradational evolution across an open, unstructured shelf platform whereas offshore Columbus Basin reservoirs exhibit a much more wave influenced, aggradational architecture, in a growth-fault dominated shelf setting. This results in significant differences in reservoir properties. Cruse reservoirs are much thinner and laterally more extensive than stacked, thicker but laterally confined (to growth compartments) offshore equivalents, resulting in a much higher hydrocarbon yield per unit area in the latter. The growth structures of the latter also provide more abundant traps. The work has allowed for a better understanding of reservoirs in the Cruse Formation, which serves as an important tool for present, as well as future exploratory and production activity planned for onshore Trinidad.