An experimental procedure is presented for determining the CO2 minimummiscibility pressure for a reservoir oil. The procedure consists ofperforming CO2 displacements at various pressure levels in a sand-packedslim tube. A correlation is presented for predicting reservoir oil CO2minimum miscibility pressures based on reservoir temperature and bubble-point pressure. Introduction The injection of carbon dioxide (CO2) for secondary andtertiary oil recovery has received considerable attention inthe industry because of its high displacement efficiencyand relatively low cost. Miscible recovery of a reservoiroil can be achieved by CO2 displacement at a pressurelevel greater than a certain minimum. This minimumpressure is hereafter defined as the CO2 minimummiscibility pressure (MMP).The CO2 MMP is an important parameter for screeningand selecting reservoirs for CO2 injection projects. Forthe highest recovery, a candidate reservoir must becapable of withstanding an average reservoir pressure greaterthan the CO2 MMP. A knowledge of the CO2 MMP is alsoimportant when selecting a model to predict or simulate reservoir performance as a result Of CO2 injection.Methods of predicting CO2 MMP's based on reservoircomposition and reservoir temperature have beenpresented in the literature. These methods have limitationsthat can result in large discrepancies when compared withexperimentally determined values. In addition, there isno generally accepted standard method in the literature forexperimentally determining the CO2 MMP for an oil.An experimental study was undertaken to obtain abetter understanding of the effects of temperature and oilcomposition on the CO2 MMP determined for an oil. CO2MMP's were determined using the sand-packed coil (orslim-tube)method. Results of this study were used todevelop a correlation for predicting the CO2 MMP foran oil.The purpose of this paper is to present the correlation for predicting CO2 MMP's that was developed from thisstudy. Another purpose is to propose that the sand-packedcoil method be used as a standard method ofexperimentally determining the CO2 MMP for an oil. Experimental StudyExperimental Variables Two variables were considered in this study: oilcomposition and temperature. Oils were considered to consist ofthree fractions: a light fraction consisting primarily of C1and small amounts of N2 and CO2; an intermediatefraction consisting of hydrocarbons with molecular weightsbetween C2 and C6; and a heavy fraction (C7+)consisting of hydrocarbons with molecular weights equal to orgreater than normal C7. The oils discussed in this paperwere prepared by combining the molar amounts of thesefractions in varying proportions. In general, the sameC7+, fraction was recombined with different amounts ofthe light (C1 + CO2 + N2) and intermediate (C2 - C6)fractions. With the exception of one oil, the same ratio ofone component to another within each fraction wasmaintained regardless of the total amount of the fraction in anyoil. The C7 + fraction was prepared by batch distilling awest Texas 30 degrees API (0.87-g/cm) separator oil. Thisdistillation had approximately five theoretical plates and wasperformed at atmospheric pressure and 208 degrees F (98 degrees C). JPT P. 160＾

Miscible gas flooding using an alternate gas/water injection process (AGWIP) is presently being applied for enhanced oil recovery (EOR) in several waterflooded reservoirs. 14 A mobile-water saturation in the vicinity of the miscible displacement front can occur in this process. To design field applications of miscible gas floods properly, it is necessary to understand the effects of water saturations above the connate saturation on the oildisplacement efficiency. Previous research on AGWIP has involved water-wet long-core flow tests using an injected solvent that is first-contact miscible with the inplace oil. 5-13 Miscible floods employing CO 2 , enriched gas, methane, and flue gases, however, are rarely firstcontact miscible with reservoir oils; the oil miscibility is normally achieved by a multiple-contact mechanism.This paper discusses the effects of mobile water on multiple-contact miscible displacements under waterand oil-wet conditions. Tests were conducted in 8-ft (244-cm) water-and oil-wet Berea cores in which C02 and water were injected both separately and simultaneously to displace a reservoir oil. The data presented focus on effects of water in the oil-moving zone (OMZ) where the CO 2 is generating miscibility with the oil and mobilizing residual oil to waterflooding. Special emphasis is placed on understanding the effect of mobilewater saturation on the oil-displacement efficiency and the component transfer between phases necessary to develop miscibility in the CO 2 /reservoir-oil system.This study demonstrates that reservoir wettability is a key factor in the performance of AGWIP. Gas/water injection can, under certain conditions, have adverse ef-0197· 7520/8310061-0687$00.25 JUNE 1983 fects on characteristics of the OMZ. These effects are in part caused by the water trapping portions of the oil and solvent. It was observed that mobile water did not change the mass transfer process by which miscibility develops in a multiple-contact miscible displacement.

Yellig, William F., SPE, Amoco Production Co. Abstract This paper presents results of an extensive study to understand CO2 displacement of Levelland (TX) reservoir oil. The work was conducted to support Levelland CO2 pilots currently in progress. Experimental displacement tests were conducted at various pressures, core lengths, and CO2 frontal advance rates. The experimental system included a novel analytical technique to obtain effluent compositional profiles within the oil-moving zone at test conditions. The results of this study show that at pressures greater than the CO2 minimum miscibility pressure (MMP), a multicontact miscible displacement mechanism predominates. Miscibility is developed in situ by vaporization or extraction-type mass transfer. The laboratory lengths required for CO2 to develop miscibility and exhibit miscible displacement efficiency were found dependent on the phase equilibria of the CO2/Levelland oil system. Displacements requiring the greatest length to develop miscibility were at pressures where single-contact mixtures of CO2 and Levelland oil form two liquid phases. A companion paper demonstrates the use of the analytical technique developed in this study to obtain process data from a CO2 field pilot test. In addition, the mechanistic information obtained from this study is used to interpret the process data from the pilot test. The results have application to other reservoir oils whose phase equilibria with CO2 are similar to the CO2/ Levelland oil system. Introduction Miscible CO2 flooding is developing rapidly as a commercial enhanced oil-recovery process. The successful design and interpretation of CO2 pilot tests and fieldwide floods are dependent on a good knowledge of the reservoir and the CO2 displacement process. The overall CO2 displacement process is shown schematically in Fig. 1. The main focus of this study concerned the oil moving zone (OMZ) and particularly the mechanisms by which this zone formed and by which CO2 displaced Levelland oil. Levelland oil was chosen because it is typical of many west Texas reservoir oils being considered for CO2 flooding. In addition, the CO2 pilot tests currently conducted in the Levelland field provide a direct application of this research. Several authors have discussed the displacement of reservoir oil by CO2. These discussions have centered around three primary displacement mechanisms: immiscible, multicontact or developed miscible, and contact miscible. In addition, two basic types of mass transfer have been postulated as responsible for the development of miscibility in a multicontact process: transfer of hydrocarbons from the in-place oil to the displacing CO2 (i.e., vaporization or extraction) and transfer of CO2 to the in-place oil (i.e., condensation). Vaporization and extraction are the same basic mass-transfer process. Vaporization refers to mass transfer from a liquid oil phase to a CO2-rich vapor phase and extraction refers to mass transfer from a liquid oil phase to a CO2-rich liquid phase. The distinction between vaporization and extraction is somewhat arbitrary in describing the CO2 process since it reflects the types of phases present only on first contact. One purpose of this paper is to present results of a comprehensive study to determine the mechanism by which CO2 displaces Levelland oil at reservoir conditions. SPEJ P. 805^

This paper presents matches, using a fully compositional model, of the performances of seven laboratory CO2 displacements of a 10-component synthetic oil. The criteria for achieving a match of laboratory performance include (1) comparisons of predicted and experimentally determined oil recovery and (2) effluent compositional profiles for each component as functions of hydrocarbon pore volumes (HCPV) of CO2 injected.An equation of state was tuned to predict single-contact (PVT) phase equilibria for CO2/synthetic-oil mixtures. The model incorporates this equation of state to predict the multiple-contact phase equilibria during a CO2 displacement test. Input to the model were independently determined gas/oil relative permeability characteristics and - for each laboratory displacement - injection rate, effluent pressure, pore volume, and temperature.The experimental displacements were conducted in linear Berea core systems using a synthetic (C1-C14) oil at 120 and 150 degrees F. Three displacements at 120 degrees F have been published by Metcalfe and Yarborough. Previously, it was thought that these displacements were conducted at selected pressures so that oil displacements encompassed immiscible, multiple-contact miscible (MCM), and contact miscible mechanisms. However, the model results show that only contact miscible and MCM displacement mechanisms were involved. To confirm the mechanistic understanding at 120 degrees F, three additional laboratory displacements were conducted at 150 degrees F. These encompassed pressures such that the displacement was controlled by an immiscible, an MCM, and a contact miscible mechanism, respectively. The model results at 150 degrees F match the experimental data and confirm the mechanistic understanding. The experimental and numerical results are in agreement with the minimum miscibility pressure theory of Yellig and Metcalfe.The results of this study confirm the importance of experimentally determined effluent compositional profiles and fully compositional models for CO2 mechanism studies. Introduction A mechanistic understanding of oil displacement by CO2 is basic to establishing the CO2 requirements and predicting performance for field projects. The petroleum engineering community relies heavily on fully compositional models and sophisticated laboratory experiments to acquire this mechanistic understanding.Currently, it is not deemed feasible to use fully compositional models to simulate performance of field-wide miscible floods. However, these models should be capable of predicting performances of laboratory-scale displacements. The results of such predictions will identify important variables that control oil recovery and that must be incorporated in mechanistically simpler field performance simulators. Further, confidence in field models will be enhanced greatly by the demonstrated ability to predict laboratory floods.Studies to improve the effectiveness and efficiency of multicomponent compositional simulators have been reported. A cell-to-cell flash model has been used to study mechanisms in rich-gas drives. However, no investigations have been reported previously that demonstrate that a fully compositional model can predict results of rich gas or CO2 laboratory displacements, including prediction of the phases and compositions developed in situ. SPEJ P. 89^

Miscible solvent slug size, and therefore cost, is dependent on the mixing or dispersion taking place in the reservoir. Fluid mixing can also be important in the interpretation of laboratory simulations of miscible floods. An experimental program was conducted to study the effects of velocity, viscosity ratio, rock type and core length on dispersion (mixing) coefficients measured in short cores, with the objective of scaling laboratory measurements to field systems. Statistical analysis of the results of the tests, matched with the capacitance-dispersion ("dead-end core volume") model, shows that an effective dispersion coefficient derived from the model is the most consistent measure of mixing in the systems studied. Viscosity ratios differing by ±4%from unity had no significant effect on the effective dispersion coefficient. The effect of system length on the effective dispersion coefficient Is shown. Because of the length dependence, dispersion coefficients measured in short laboratory systems may underestimate the true dispersion taking place in the reservoir. The length dependence of the dispersion coefficient may also have important implications in the interpretation of laboratory results where mixing is a factor. INTRODUCTION Economical enhanced oil recovery requires injection of a relatively small slug of solvent or oil mobilization fluid, e.g., CO2 rich gas or micellar fluid. A chase fluid (N2 flue gas or polymer water), which is miscible with the solvent, is generally used to maximize solvent utilization. A physical phenomenon referred to as dispersive mixing acts to reduce the effectiveness of the solvent. Dispersive mixing also decreases the effectiveness of chase fluid in displacing the solvent. Therefore, the effect of dispersive mixing on the process must be included in numerical models for the design of enhanced oil recovery projects. Various mathematical models have been propsoed to simulate the dispersive mixing which occurs in oil reservoirs(1). These models include the simple dispersion model and the capacitance-dispersion model. The dispersive mixing simulated by these models is characterized by adjustable parameters. The parameters must be determined or estimated for a porous medium in order to simulate the dispersive mixing which will take place between miscible fluids flowing through it. In previous work on dispersive mixing(2), a technique was developed to determine the dispersion coefficient for a consolidated core. This technique consists of conducting displacements in the core of interest with equal-viscosity-contact miscible fluids and matching the effluent concentration data with a dispersive mixing model. This work concluded that for many systems the simple dispersion model was not adequate. The capacitance-dispersion model was shown(2) to better simulate the dispersive mixing in these systems. This model includes additional parameters which allow it to fit more irregular effluent concentration profiles with greater accuracy. The work described in this paper is a continuation of the miscible-displacement, dispersion-coefficient study. The prinicpal objectives of this work were to:determine the physical significance of the parameters of the capacitance-dispersion model;determine the validity of using an "effective dispersion coefficient" defined by this model to simulate dispersive mixing; andshow that as system length increases the dispersive mixing for heterogeneous systems can be simulated by a simple dispersion model with an "effective dispersion coefficient."