Browsing by Subject "Three-phase"
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Item Compositional three-phase relative permeability and capillary pressure models using Gibbs free energy(2016-08) Sadeghi Neshat, Sajjad; Pope, G. A.; Ezekoye, Ofodike E.; Lake, LarryBoth relative permeability and capillary pressure depend on composition as well as saturation, but classical models neglect this dependence. The objective of this research was to develop coupled three-phase relative permeability and capillary pressure models for implementation in a four-phase flow compositional equation-of-state simulator. The models applied to several complex but practical reservoir simulation problems. Models independent of phase label have many advantages in terms of both numerical stability and physical consistency. Identification of hydrocarbon and aqueous phases based on their molar Gibbs Free Energy (GFE) is a key feature of the new model. Instead of using labels (gas/oil/2nd liquid/aqueous) to define permeability parameters such as end points, residual saturation and exponents, the parameters are continuously interpolated between reference values using the Gibbs free energy of each phase at each time step. Consequently, the formulation used to implement other relevant physical parameters must be consistent with the new approach. A comprehensive but simple vii algorithm was developed for this purpose. The algorithm allows for very general threephase hysteresis in both relative permeability and capillary pressure. An important part of this thesis is analyzing the results of a recent series of experiments on the effect composition on relative permeability. These new data were used to calibrate the new GFE relative permeability model and apply it in a compositional reservoir simulator. The robustness of the new GFE model was shown through complex simulations such as solvent flooding, miscible/immiscible WAG processes, well stimulation processes using solvents to remove condensate and/or water blocks in both conventional and unconventional formations and other challenging applications involving both mass transfer between phases and phase changes. The interpolation of relative permeability parameters based on GFE instead of phase labels completely solves the discontinuity problem caused by phase flipping or misidentification. Therefore, simulations run significantly faster and are physically correct. The novelty of this research is in integrating and unifying relevant physical parameters including trapping number, hysteresis and capillary pressure into one rigorous algorithm with compositional consistency and in the development and application of a practical procedure for numerical compositional reservoir simulations.Item Development of compositional three-phase relative permeability and hysteresis models and their application to EOR processes(2016-12) Mohammad Reza Beygi, Mohammad Reza; Delshad, Mojdeh; Wheeler, Mary F. (Mary Fanett); Pope, Gary A; Sepehrnoori, Kamy; Mohanty, Kishory K.; Arbogast, ToddEnhanced oil recovery (EOR) techniques have the potential to improve hydrocarbon recovery and project economics substantially. Characterizing fluid displacement and the relevant multiphase flow properties are essential to modeling EOR processes to reliably forecast the performance and economics. The spatial-temporal distribution of fluids spans a broad spectrum of composition and saturation spaces. In addition, a fundamental understanding of characteristic parameters of interphase mass-transfer in various EOR applications is crucial to capture and model fluid displacement. Relative permeability is a critical characteristic petrophysical property for modeling fluid displacement in porous media. Also, hysteresis phenomena govern physics of fluid flow in many subsurface applications such as multicyclic EOR processes, geological CO2 sequestration, and natural gas storage. Capillary trapping is the essence of hysteresis to trap fluids. In this research, we developed a high-fidelity computational tool for integrating compositional three-phase relative permeability and hysteresis to assist in accurate modeling of multicycle and compositional EOR methods. This viable tool can be implemented into general-purpose reservoir simulators to model field-scale projects. It consists of an integrated compositionally-consistent three-phase relative permeability and three-phase hysteresis models. The developed three-phase relative permeability model is valid on entire saturation and composition spaces, is simple with one free parameter for each phase, and is versatile for all phases and wettability states. The general model is saturation-path dependent and adopts a linear saturation-weighted interpolation scheme for calculation of relative permeability parameters. For the compositional relative permeability modeling, we developed a general framework applicable to hydrocarbon and non-hydrocarbon phases. The developed framework provides a pragmatic approach for adding the direct impact of composition, pressure, and temperature and is independent of the conventional phase-labeling method. The proposed framework unifies thermodynamics, petrophysics, and geochemistry to enhanced relative permeability modeling. Relative permeability parameters are calculated based on a mapping scheme of current-state bulk and interphase Gibbs free energy onto corresponding initial-state values. We applied the developed framework to modeling lowsalinity waterflood and complex fluid displacement of near-critical fluids. The three-phase hysteresis model provides a general and straightforward approach for calculation of capillary trapping in multicyclic processes. The developed hysteresis model provides a set of cycle-dependent relative permeability curves and applies to any three-phase relative permeability model by incorporating the free-saturation concept. We implemented the developed toolbox into two in-house compositional reservoir simulators (i.e., IPARS and UT-DOECO2). Several synthetic field cases are discussed to validate the implemented models conceptually. Using the enhanced simulators, we demonstrated accurate modeling of multiphase fluid displacement and trapping in EOR processes such as water-alternate-gas injection scheme, low-tension gas flood (i.e., foam), and carbon capture, utilization, and storage (CCUS).Item Experimental Study of Multiphase Pump Wear(2014-08-06) Steck, Daniel D'AndreaThe goal of this research is to better understand upstream Oil & Gas Electric Submersible Pump (ESP) reliability issues. The objective of this research is to determine how Liquid-Gas-Particulate (LGP) turbine pump wear differs from Liquid-Particulate (LP) turbine pump wear. This objective is novel because little is known about LGP wear, yet such wear is common in ESPs. To accomplish the research objective, an experimental study of a gas handling ESP was conducted. Tests of two Baker Hughes 1025 MVP G400 Severe Duty turbine pumps were conducted with water, air, and sand. One pump was tested with a Gas Volume Fraction (GVF) of 20% while the other was tested with a GVF of 0%. It was found that particulates migrate radially outward through the pump and cause diffuser sidewall wear to increase through the pump. It was also found that various impeller flow path areas experience more LGP wear than LP wear. In general, pump wear progress faster for LGP wear than for LP wear. It is believed that this is caused primarily by the thinning effect that gas can have on a fluid?s viscosity.Item Measurement and modeling of three-phase oil relative permeability(2011-12) Dehghanpour, Hassan; DiCarlo, DavidRelative permeabilities for three-phase flow are commonly predicted from two-phase flow measurements using empirical models. These models are usually tested against available steady state data. However, the oil flow is unsteady state during various production stages such as gas injection after water flood. Accurate measurement of oil permeability([subscript ro]) during unsteady tertiary gas flood is necessary to study macroscopic oil displacement rate under micro scale events including double drainage, coalescence and reconnection, bulk flow and film drainage. We measure the three-phase oil relative permeability by conducting unsteady-state drainage experiments in a 0.8m water-wet sandpack. We find that when starting from capillary-trapped oil, k[subscript ro] starts high and decreases with a small change in oil saturation, and shows a strong dependence on both the flow of water and the water saturation, contrary to most models. The observed flow coupling between water and oil is stronger in three-phase flow than two-phase flow, and cannot be observed in steady-state measurements. The results suggest that the oil is transported through moving gas/oil/water interfaces (form drag) or momentum transport across stationary interfaces (friction drag). We present a simple model of friction drag which compares favorably to the experimental data. We also solve the creeping flow approximation of the Navier-Stokes equation for stable wetting and intermediate layers in the corner of angular capillaries by using a continuity boundary condition at the layer interface. We find significant coupling between the condensed phases and calculate the generalized mobilities by solving co-current and counter-current flow of wetting and intermediate layers. Finally, we present a simple heuristic model for the generalized mobilities as a function of the geometry and viscosity ratio. To identify the key parameter controlling the measured excess oil flow during tertiary gasflood, we also conduct simultaneous water-gas flood tests where we control water relative permeability and let water saturation develop naturally. The measured data and pore scale calculations indicate that viscous coupling can not explain completely the observed flow coupling between oil and water. We conclude that the rate of water saturation decrease, which controls the pore scale mechanisms including double drainage, reconnection, and film drainage significantly influences the rate of oil drainage during tertiary gas flood. Finally, we present a simple heuristic model for oil relative permeability during tertiary gas flood, and also explain how Stone I and saturation-weighted interpolation should be used to predict the permeability of mobilized oil during transient tertiary gasflood.Item Measurement and modeling of three-phase relative permeability as a function of saturation path(2016-05) Kianinejad, Amir; DiCarlo, David Anthony, 1969-; Balhoff, Matthew; Delshad, Mojdeh; Johns, Russell; Prodanovic, Masa; Sepehrnoori, KamyThree-phase flow occurs in many petroleum recovery processes, especially during tertiary recovery. One of the most important parameters to accurately model these complex processes at large scale is relative permeability to each of the flowing fluids. However, relative permeability in three-phase systems becomes extremely complicated due to different flow mechanisms involved with three-phase flow as well as dependence of relative permeability on saturation path (water and oil saturations at each time in three-phase saturation space). During the past several decades, many studies reported experimental measurements of relative permeabilities in three-phase systems under different rock and fluid properties. Based on these measurements, several empirical models have been developed to predict relative permeabilities in three-phase space. However, the performance of these models have been frequently reported to be poor in reproducing experimental data. This indicates that despite the great effort during the past decades, there are still some aspects of three-phase space that have not been completely understood. Therefore, in this study we attempt to obtain a better physical understanding of three-phase relative permeability through extending relative permeability measurements over the entire three-phase phase space with different fluids and porous media. To do so, we use a gravity drainage method to measure three-phase relative permeabilities. However, previous applications of this method suffered from three main issues: a) relative permeabilities at medium to high saturations were not accessible due to quick saturation changes at early times of experiments, b) saturation path of experiments was out of control, and c) it was only applicable to unconsolidated sandpacks. In this study, we develop new procedures and methods to overcome the mentioned shortcomings of this method, by combining the method with steady-state method and applying a small gas pressure gradient. These improvements to the method allows us to measure relative permeabilities along different saturation paths, in both consolidated and unconsolidated porous media while extending the relative permeability measurements to higher saturation regions. In particular, we measure three-phase relative permeabilities along several saturation paths during unsteady-state gravity drainage experiments in two consolidated and unconsolidated media, with oils varying in composition, viscosity, and spreading coefficient. The method involves measurement of in-situ saturations along the porous media at different times during the experiments. These saturation profiles are then used to directly obtain three-phase relative permeabilities. We find that in our water-wet media, oil relative permeability varies significantly depending on the saturation path, while water relative permeability remains unchanged. In addition, oil relative permeabilities along different saturation paths extrapolate to different residual oil saturations. Interestingly, we find that once the measured relative permeabilities along different saturation paths are plotted as a function of mobile oil saturation, So-Sor, all of the differences between relative permeabilities vanish and they all form a single relative permeability curve. We compare our data with the relative permeability data published over the past several decades. We find that literature data are in complete agreement with our data. In addition, literature data for water-wet media suggest that for each media, experiments which end up at a different residual saturation result in a different relative permeability curve. This is while the experiments which reach to the same residual oil saturation result in the same oil relative permeability, regardless of their saturation paths. We examine the importance of residual oil saturation using three most commonly used relative permeability models against our data. These models consist of Corey, saturation weighted interpolation (SWI), and Stone. The idea is simply to change residual oil saturation while keeping all the other parameters constant, to fit experimental data along different saturation paths. We find that, by changing residual saturations, Corey and SWI models fit the data well, while the Stone model fails at low saturations. Overall, we find that the key to modeling relative permeability of water-wet media in three-phase space is residual oil saturation. Our data suggests that three-phase oil relative permeability is only a function of mobile oil saturation, and residual oil saturation is a non-linear function of water saturation.