Methods for miscible flooding have been researched and field tested since the early 1950's. This paper reviews the technical state of the art and field behavior to date for the major miscible flood processes: first-contact miscible, rich-gas drive, vaporizing-gas drive, and carbon dioxide flooding. Important technological areas selected for review include phase behavior and miscibility, sweepout, unit displacement efficiency, and process design variations. Carbon dioxide flood technology is emphasized, and several technical issues are identified that still need to be resolved. Rules of thumb and ranges of conditions are discussed for applicability of each process. A comparison is made of the incremental recovery and solvent slug effectiveness observed in field trials of the different processes. From the limited data available, processes. From the limited data available, there is no clear-cut evidence that field results on average and for a given slug size have been appreciably better or poorer for one process compared with another. Introduction The search for an effective and economical solvent along with development and field testing of miscible-flood processes has continued since the early processes has continued since the early 1950's. Early focus was on hydrocarbon solvents, and three types of hydrocarbon-miscible processes were developed: the first-contact miscible process; the vaporizing-gas drive process, often called high-pressure gas drive; and the rich-gas drive process, often called condensing-gas drive. First-contact miscible solvents mix directly with reservoir oils in all proportions and their mixtures always remain proportions and their mixtures always remain single phase. Other solvents are not directly miscible with reservoir oils, but under appropriate conditions of pressure and solvent composition these solvents can achieve miscibility in-situ by mass transfer of oil and solvent components through repeated contact with the reservoir oil. miscibility achieved in this manner is termed multiple-contact or dynamic miscibility. The vaporizing-gas drive process achieves dynamic miscibility by in-situ vaporization of intermediate molecular weight hydrocarbons from the reservoir oil into the injected gas. Dynamic miscibility is achieved in the rich-gas drive process by in-situ transfer of intermediate molecular weight hydrocarbons from the injected gas into the reservoir oil. Propane or LPG mixtures typically were the solvents used in first-contact hydrocarbon miscible flooding, whereas natural gas at high pressure and natural gas with appreciable concentrations of intermediate molecular weight hydrocarbons were injection fluids in vaporizing-gas drive and rich-gas drive floods. The high cost of propane, LPG, or rich hydrocarbon gas propane, LPG, or rich hydrocarbon gas dictated that these solvents be injected as slugs which usually were driven with natural gas. Flue gas and nitrogen also have been found to achieve dynamic miscibility at high pressures with some oils by the vaporizing-gas drive mechanism. Hydrocarbon miscible processes have received extensive field testing since the 1950's, primarily in the United States and Canada. Over 100 projects were initiated during this time period. The majority were small-scale pilot tests involving one or at most a few injection wells; however, a number of large projects were undertaken involving several thousand acres or more (more than 4 000 000 m2). A few projects tested flue gas injection.
This paper gives an overview of the carbon dioxide miscible-flooding process, reviews current technology, discusses past and current field process, reviews current technology, discusses past and current field testing, and assesses the state-of-the-art. Carbon dioxide sources are identified and evaluated. Potential oil recovery, producing rates, and future outlook are projected. Introduction Use of carbon dioxide to increase oil recovery is not a new idea. As early as 1952, Whorton and Brownscombe received a patent for an oil-recovery method with CO2. Laboratory research was published through the 1950's and 1960's and research continues today. Carbon dioxide has been investigated for miscible displacement, for immiscible displacement, for producing well stimulation, and for carbonated producing well stimulation, and for carbonated waterflooding. There have been a few field tests in the past, and currently some commercial oil recovery exists. past, and currently some commercial oil recovery exists. Since 1973, rising oil prices coupled with declining domestic production have caused an intense interest in enhanced oil-recovery methods. Several recent studies of the potential for enhanced recovery found carbon dioxide miscible flooding could become one of the most important of these methods. Current industry interest in CO2 miscible flooding is high, as evidenced by the level of activity in field testing and CO2 source development. Two studies are in progress to determine the feasibility of building large pipelines to supply carbon dioxide to west Texas oil fields. Although there may be some important future applications for well stimulation and for immiscible displacement, this paper provides an overview of only miscible flooding with carbon dioxide. Current technology, extent of field testing, state-of-the-art, potential carbon dioxide sources, and future outlook are discussed in the following sections. Review of Current Technology Mechanism for Achieving Miscibility Carbon dioxide is not directly miscible with most crude oils at attainable reservoir pressures. If CO is added continuously to oil in an equilibrium cell, two or more phases will form, depending on over-all mixture phases will form, depending on over-all mixture composition. Past research shows that with some oils, CO2 partially dissolves in oil as it flows into the reservoir, while partially dissolves in oil as it flows into the reservoir, while extracting or vaporizing hydrocarbons at the same time. 11-13 The displacing gas front becomes enriched with these extracted hydrocarbons and, at sufficiently high pressure, enrichment proceeds to such an extent and so pressure, enrichment proceeds to such an extent and so alters the composition of the gas front that an efficient displacement occurs, which is characteristic of miscible displacement. This mechanism for achieving miscibility is similar to the high-pressure gas mechanism for hydrocarbon miscible displacement with lean natural gas, but CO2 is a much more powerful vaporizer of hydrocarbons than natural gas, extracting hydrocarbons primarily in the gasoline and gas-oil range. Recent research shows that with other oils, continued contact of the oil by CO2 alters the oil composition to the point where miscibility occurs with the CO2. The mechanism here is analogous to the rich-gas drive mechanism for achieving miscibility between oil and a hydrocarbon gas enriched with intermediate hydrocarbons. With either mechanism, the pressure required for miscibility with CO2 is usually significantly lower than the pressure required for miscible displacement with either natural gas, flue gas, or nitrogen.An example of oil recovery by carbon dioxide flooding at various pressures is shown in Fig. 1 for a west Texas reservoir oil. Displacements were made in both a 42-ft consolidated Boise sandstone and in a 20-ft unconsolidated sand pack initially saturated with oil. JPT P. 1102
Displacements oj laboratory oils by propane in long, consolidated sandstone cores in the presence of high water saturations have shown that oil recoveries approaching 100 percent may be realized by continuous water.propane injection, even for oil saturations close to residual oil. However, it was o/ten necessary to inject many pore volumes of solvent to attain this high a recovery Initial oil saturations were established by injecting water and oil at a constant ratio intc the porous medium containing residual oil to a waterflood until a steady state was obtained. Propane and water were then injected in the same fixed ratio to displace the oil. These and other experiments indicate that in the presence of a high water saturation only part of the oil is /lowabIe. Part resides in locations that are blocked by water, and the oil in these stagnant locations is not f!owabIe. This nonflowable oi[, it is believed, can be recovered by molecular diffusion into tbe flowing propane of a water-propane displacement. Values for the saturation of hydrocarbon that is contained in the stagnant locations and values /or the ratio of the longitudinal hydrodynamic-dispersion coefficient to displacement velocity were determined at various water saturations in the test sandstones. The data suggest that rock wettabiiity may inf Iuence the stagnant saturation and that stagnant oil saturations may not be as large in reservoir rocks as they are observed to be in laboratory sandstones. Mass transfer between the fIowing solvent and hydrocarbon components in tbe stagnant saturation was expressed by a first-order rate expression. Rough values for tb~mass transfer coefficients /or the propane-trimetbylhexane hydrocarlw~pair were estimated from exp erir.zents. Computations using these values for mass trans~er coefficients indicate that exp era"ments in laboratory-size cores may show much poorer displac~ment efficiency than that which might actually occur in the field.
SPE Member Abstract There is mounting evidence for some reservoir fluids that phase behavior in condensing-gas drives departs substantially from traditional concepts deduced for three-component fluids and that transition-zone compositions are established by a condensing/vaporizing mechanism rather than by condensation alone. To what extent does displacement behavior depart from traditional concepts as well and what is the significance of any departures? This paper addresses these questions through a series of compositional simulations for displacement in a one-dimensional slim-tube. The simulations show that displacement behavior for a reservoir fluid does not depart substantially from traditional condensing-gas drive concepts for three-components even though the transition-zone building mechanism is one of condensation/vaporization. They show that when injection gas enrichment exceeds a critical value, displacement behavior of the reservoir fluid becomes miscible-like in the following important respects:recovery is essentially 100% after one pore volume of injection in the limit of no dispersion, andfor a realistic level of dispersion, recovery at 1.2 pore volumes injected is insensitive to both relative permeability and relative permeability end-point saturation. Also, as with traditional concepts, the critical enrichment can be determined from slim-tube displacements by finding the point of breakover in a plot of oil recovery at 1.2 PV of injection vs. gas enrichment. However, with the reservoir oil, gases enriched above the critical value show a converging/diverging type of phase behavior on a pseudoternary diagram, and they leave a residual oil saturation, both of which are contrary to traditional concepts. The magnitude of the residual oil saturation depends primarily on mixing caused by diffusion/dispersion and should be relatively small, less than about 5% PV, in reservoir floods and even less in slim-tube displacements. All the simulations were highly sensitive to the number of grid blocks used to model the slim-tube. This effect must be accounted for when simulated slim-tube behavior is compared with experiments, and it must be addressed in reservoir simulations. Simulations of 20% HCPV enriched-gas slugs driven by water show that a very high level of mixing shifts the point of optimum solvent enrichment to higher values. Numerical dispersion will cause this shift, even in simulations with as many as 100 grid blocks representing displacement length. Whether or not physical dispersion in the reservoir is great enough to cause it is an unanswered question. Introduction Traditional condensing-gas drive concepts of phase behavior, miscibility, and displacement behavior derive from the behavior of three-component fluids. This is true also for the interpretation of slim-tube experiments for minimum miscibility pressure or required gas enrichment. P. 171^
An elution gas that might be either a single component or a binary mixture, but which in any case was appreciably soluble in the fixed liquid phase on the column matrix material, was used to form a multicomponent liquid phase within the chromatographic column. Vapor-liquid equilibrium was studied both with the solute of interest a t essentially infinite dilution conditions and with the solute present at some finite concentration in both phases. From the elution data vapor-liquid equilibrium ratios, or K values, were calculated by expressions relating the solute retention volume to the solute K value in the vapor-liquid system maintained within the chromatographic column.Data were taken for the solutes ethane, propane, and n-butane a t infinite dilution in the methane-n-decane system a t 160°, 70°, 40", Oo, and -2OOF from 20 to 2,000 lb./sq. in.; for propane a t infinite dilution in methane-n-hexodecane a t 7OoF and 20 to 200 Ib./sq. in.; and propane in the system methane-propane-n-decane a t 40°F from 20 to 460 Ib./sq. in. The univariant gas-liquid-solid locus was experimentally determined for the methane-n-decane binary system. The chromatographically determined K values for n-butane a t infinite dilution in methane-n-decane were compared with published static equilibrium values and found t o be in substantial agreement. Activity coefficients calculated from the data for a11 the solute isotherms were compared a t atmospheric pressure with the results of the Bronsted and Kaefoed relation tor estimating activity coefficients of hydrocarbons, and close agreement was again found.
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