Analytical solutions are presented that confirm the existence of a combined condensing and vaporizing displacement mechanism in enriched gas drives. The solutions are derived for dispersionfree, one-dimensional displacements in four-component hydrocarbon systems. A simple geometric construction is used to find a key tie line in the solution, the "crossover" tie line. This tie line is shown to control the development of miscibility in condensing/vaporizing systems, and it connects the condensing and vaporizing portions of the displacement. 7
Asphaltene nanoaggregates have recently been observed in live crude oil by observation of gravitationally induced asphaltene gradients in four different reservoir sands with oil columns up to 1000 m vertical. When the liquid phase is invariant, these gradients can be fit using Archimedes buoyancy in the Boltzmann distribution; the only adjustable parameter in data fitting is the size of the asphaltene nanoaggregate; ∼2 nm is obtained in four reservoir sands and is similar to laboratory results for asphaltene nanoaggregates in toluene. Here, a live crude oil (with dissolved gases) has been spun at modest g forces for long times designed to create a large, equilibrium asphaltene gradient for the presumed 2 nm aggregates. Elevated temperatures (∼91°C) were employed during centrifugation to mimic reservoir conditions for asphaltene aggregation and prevention of a possible wax phase. Elevated pressures were employed on the hot, live crude oil to maintain dissolved gas concentrations. A total of 13 alliquots of crude oil were removed after centrifugation, and the asphaltene concentrations were determined by optical spectroscopy. Indeed, a large asphaltene gradient was observed, and a 2.6 nm diameter nanoaggregate was obtained using Archimedes buoyancy in the Boltzmann distribution. In addition, a solubility model accounting for the gas/oil ratio (GOR) gradient was used to analyze the asphaltene gradient, giving an asphaltene particle size of 2.0 nm, thus, the same as field observations. In addition, the gradient in bulk resins was shown to be quite small, showing the stark contrast of asphaltene versus bulk resin aggregation. The heaviest resins (or lightest asphaltenes) do show some gradient. These observations allow for the determination of the maximum and minimum asphaltene aggregation number; the range is roughly 3-8. Some modest resin association with asphaltenes, one resin molecule in every asphaltene nanoaggregate, is consistent with our data. These results are discussed within the increasingly successful modified Yen model of asphaltenes.
A rigorous tie-line extension criterion for the minimum miscibility pressure (MMP) is derived for dispersion-free, ID displacements in four-component systems in which CO 2 displaces oil containing dissolved methane. The key tie-lines required for application of the MMP criterion are obtained by a simple graphical construction. A simplified technique for construction of solutions is demonstrated for the C0 2 /methane/butane/decane system. The new technique makes solution of certain four-component problems not much more difficult than solution of a Buckley-Leverett displacement of oil by water.
Local displacement efficiency from CO2 gas injection is highly dependent on the minimum miscibility pressure (MMP). Correlations are often used to estimate the MMP where the injected fluid may or may not contain impurities such as methane. These correlations, however, are based on a limited set of experimental data and as such are not widely applicable. They also do not accurately account for the more complex condensing/vaporizing displacement process. This paper presents new MMP correlations for the displacement of multicomponent oil by CO2 and impure CO2. The approach is to use recently developed analytical theory for MMP calculations from equations-of-state (EOS) to generate MMP correlations for displacements by pure and impure CO2.1–8 The advantage of this approach is that MMPs for a wide range of temperatures and reservoir fluids can be calculated quickly and accurately without introducing uncertainties associated with slim-tube MMPs and other numerical methods. The improved MMP correlation is based solely on the reservoir temperature, molecular weight of C7+, and percentage of intermediates (C2 - C6) in the oil. The MMPs from the improved correlation are compared to currently used correlations and 41 experimentally measured MMPs. Correlations are also developed for impure CO2 floods, where the injection stream may contain up to 40% methane. The new correlations are significantly more accurate and applicable than currently used correlations. Introduction Whorton et al.9 received a patent in 1952 to improve oil recovery by the injection of CO2. CO2 injection has been ongoing ever since primarily because CO2 develops multicontact miscibility (MCM) with reservoir fluids at low pressures. There are also potential environmental benefits of CO2 injection in that subsurface sequestration of greenhouse gases has become an important U.S. priority.10 The minimum pressure for miscibility (MMP) is an important optimization parameter in CO2 floods. Recoveries from slim-tube experiments often give a slope change at the MMP. Above the MMP, slim-tube recoveries (or local displacement efficiencies) typically do not increase significantly with enrichment. Thus, the accurate determination of MMP is important in gas flood design. Pseudoternary diagrams have traditionally been used to explain the behavior of multicontact miscible (MCM) gas drive processes.11–16 Real oil displacements by CO2, however, have recently been shown to have features of both vaporizing and condensing drives (CV).2,17,18 The two-dimensional nature of pseudoternary diagrams often lead to incorrect interpretations especially for CV drives. Analytical theory has no such restrictions and can be applied for any number of components.1–8 The CV process greatly complicates the accurate estimation of MMP in that miscibility is developed not at the leading edge (condensing region) or trailing edge (vaporizing region) of the displacement, but is developed in between the condensing and vaporizing regions. Four primary methods have been used in recent years to determine MMPs for specific fluid displacements: slim-tube experiments,10 compositional simulation,12 mixing-cell models,19 and analytical methods.1–8 Each of these methods has advantages and disadvantages. Slim-tube experiments use real fluids, but are expensive and time consuming to perform and can give misleading results depending on the level of physical dispersion present.20 Fine-grid compositional simulations and mixing-cell models can suffer from numerical dispersion effects and are also time consuming to perform. Dispersion-free analytical methods are often very fast, but like simulation and mixing-cell models, they rely on an accurate fluid characterization by an equation-of-state (EOS). A variety of correlations for the estimation of MMP have been developed from regressions of slim-tube data. Although less accurate, correlations are quick and easy to use and generally require only a few input parameters. Hence, they are very useful for fast screening of reservoirs for potential CO2 flooding. They are also useful when detailed fluid characterizations are not available. One significant disadvantage of current MMP correlations is that the regressions use MMPs from slim-tube data, which are in themselves uncertain.
Dimethyl Ether Enhanced Waterflood (DEW) is a novel and promising solvent-based EOR technology developed by Shell. Dimethyl Ether (DME) is a widely-used industrial chemical which is applied as a water soluble solvent for EOR applications to enhance a conventional waterflood. Once the DME-brine solution is injected into the reservoir and comes in contact with the oil, the DME molecules partition into the oil phase which leads to oil swelling and mobilization of residual oil. Moreover the partitioning of the DME into the oil phase decreases the oil viscosity and improves its mobility. The combination of these effects results in both a significantly higher ultimate oil recovery compared to the conventional waterflood as well as accelerated oil production at lower energy footprint compared to thermal technologies. As the solvent is water soluble, it can be very effectively back-recovered from the reservoir by re-dissolving the trapped DME in the DME-free chase water slug. The solvent is recovered from the produced oil and water streams at surface and re-used. The main objectives of this paper are to present the first experimental results, explain the physical mechanisms of this novel concept and demonstrate the extra oil recovery. Additionally, modeling workflows used to interpret the experiments and predict the benefits of field EOR application are illustrated.To gain an insight into physical mechanisms behind the DEW, develop modeling workflows and de-risk the technology, an extensive experimental program was set up to investigate both the fluid-fluid and rock-fluid interactions. Phase behavior of DME/brine and DME/crude mixtures has been carried out, with a focus on the partitioning of the solvent between brine and crude. Mixing rules for properties affecting the phase mobilities have been determined. In parallel, a number of coreflood experiments were conducted on both carbonate and clastic cores of varying permeability to investigate the dynamic DME/crude behavior and DME/rock interaction. PVT experiments were used to build phase equilibrium models. Based on these PVT models, the coreflood experimental data was matched and interpreted using numerical simulation.Coreflood experiments confirmed the phase behavior-driven character of the DEW technology. A good match between the experimental and simulated oil recovery was obtained in most cases. This shows that PVT models, generated using measured basic data, are in a good agreement with the dynamic coreflood experiments.
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