Multiple-contact Miscible Displacement Research Articles

A higher-order finite-difference compositional simulator

A third-order finite-difference method was applied to a new three-dimensional, four-phase, equation-of-state, compositional simulator. The third-order scheme was tested for first-contact miscible flow, waterflooding, immiscible, and multiple-contact miscible condensing gas displacements. The authors show that this method agrees with a two-dimensional, analytical solution. The authors also show that the higher-order method has less grid orientation effect than either one-point or two-point upstream weighting methods. A grid refinement study shows that it also has less numerical dispersion. This method was easy to implement and requires only a small increase in storage. Computation time can be reduced since the reduction in numerical dispersion allows larger grid blocks to be used while maintaining an accurate solution. For example, for a one-dimensional multiple-contact miscible displacement the computational time was reduced by a factor of 34.5 compared to the same accuracy using one-point upstream weighting.

Solubility and Extraction in Multiple-Contact Miscible Displacements: Comparison of N2 and CO2 Flow Visualization Experiments

Summary Results of secondary and tertiary displacements of Maljamar crude oil by N2 and CO2 are compared to examine the effects of solubility and extraction on local displacement efficiency. The flow visualization experiments were performed in pore networks etched in glass plates. In those experiments, the much higher solubility of CO2 in the oil caused only marginal improvement in displacement efficiency over that observed for N2, which was much less soluble. At pressures high enough for CO2 to extract hydrocarbons efficiently, however, displacements were much more efficient. Secondary and tertiary displacements in a more heterogeneous glass model are also compared. In a secondary displacement with high solubility but low extraction, adverse capillary and viscous effects limited the area swept to preferential flow paths. High CO2 solubility did not appear to have significant effects. When water was present in tertiary displacements with efficient extraction and high solubility, combined effects of viscous instability, capillary forces, and heterogeneity sharply reduced sweep efficiency below that observed in secondary displacements in the same model.

Effect Of Multiple-Contact Miscibility On Solvent Slug Size Determination

Abstract It is a common practice to apply the dispersion theory to simulate the idealized miscible displacement process. In applying this theory, first-contact miscibility is assumed to calculate the solvent slug size required for a successful miscible flood. For a multiple-contact miscible process such as condensing drive however, additional solvent is required because:the composition of the reservoir oil needs to be enriched to a level such that miscibility between the solvent and the enriched-oil' can be achieved;a significant amount of solvent is required to offset dilution effects and ensure that at least a thin bank of "enriched-oil" (in the solvent-'enriched-oil?-reservoir oil mixing zone) exists to maintain miscibility throughout the displacement. Despite the importance of these factors, they are seldom considered while calculating solvent slug size requirements. The main objectives of this paper are to:explain clearly how multiple-contact miscibility (condensing drive only) affects solvent slug size requirements;develop a procedure and provide standard formulas using the concept of dispersion and phase behaviour, to determine solvent slug size required for multiple-contact miscible floods. An example was used to illustrate the calculation procedures. Introduction Miscible displacement of oil may be achieved with a solvent that is in first-contact miscible with the reservoir oil, or a solvent that either condenses or vapourizes intermediate-molecular- weight components into or out of the oil, thereby establishing multiple-contact miscibility (MCM). To ensure that this behaviour will exist in the reservoir, phase behaviour studies and laboratory tests are conducted to decide on the solvent composition. The next step in the design process is to calculate the amount of solvent that must be injected to maintain miscibility for the duration of the displacement process. Generally, conventional methods of slug size determination for all of these processes account only for the effects of diffusion and dispersive mixing. However, the field performance of projects using the MCM process have indicated that large safety factors must be applied to account for other factors besides the dilution of the solvent 50 that the technical success of a project is ensured. This paper investigates the effect of multiple-contact miscibility (condensing process only) on solvent slug size determination. The processes of first-contact and multiple-contact miscible displacements, as well as the conventional method of slug size determination using diffusion and dispersion theory are reviewed. Then a simplified model of the MCM process is presented to help calculate the additional solvent required to sufficiently enrich the oil through a condensation process such that miscibility will be maintained throughout the life of a project. The effect that the degree of the enrichment of the solvent has on this calculation is also discussed, and an example of the calculation method using hypothetical data is included. Review of Miscible Displacement Processes First-Contact Miscibility (FCM) Two fluids are determined to be in first-contact miscible if they can be mixed in any proportion and result in only one phase.

Flow Visualization for CO2/Crude-Oil Displacements

Abstract Results of visual observations of high-pressure CO2 floods are reported. The displacements were performed in two-dimensional (2D) pore networks etched in glass plates. Results of secondary and tertiary first-contact miscible displacements and secondary and tertiary multiple-contact miscible displacements are compared. Three displacements with no water present were performed in each of three pore networks: (1) displacement of a refined oil by the same oil dyed a different color; (2) displacement of a refined oil by CO2 (first-contact miscible); and (3) displacement of a crude oil at a pressure above the minimum miscibility pressure. In addition, three tertiary displacements were performed in the same pore networks: (4) displacement of the refined oil by water, followed by displacement by the same refined oil dyed to distinguish it from the original oil; (5) tertiary displacement of the refined oil by CO2; and (6) tertiary displacement of crude oil by CO2. In addition, recovery of oil from dead-end pores, with and without water barriers shielding the oil, was investigated. Visual observations of pore-level displacement events indicate that CO2 displaced oil much more efficiently in both first-contact and multiple-contact miscible displacements when water was absent. In tertiary displacements of a refined oil, CO2 effectively displaced the oil it contacted, but high water saturations restricted access of CO2 to the oil. The low viscosity of CO2 aggravated effects of high water saturations because the CO2 did not displace water efficiently. CO2 did, however, contact trapped oil by diffusing through water to reach, to swell, and to reconnect isolated droplets. Finally, CO2 displaced crude oil more efficiently than it did the refined oil in tertiary displacements. Differences in wetting behavior between the refined and crude oils appear to account for the different flow behavior.

Parametric Analysis On The Determination Of The Minimum Miscibility Pressure In Slim Tube Displacements

Abstract The reservoir pressure required for the development of a dynamic vaporizing or condensing gas drive is often determined experimentally by what is referred to as the "slim-tube" displacement test. Early work has shown that, provided the displacement is stable, the determination of the minimum miscibility pressure is the only function of the thermodynamic conditions (nature of fluids and temperature). The purpose of this investigation is to verify whether the above condition holds/or conventional tests carried out in flat slim-tube coils. This has been done by examining the effect of tube length and injection rate on the displacement efficiency at various pressures covering the immiscible and multiple-contact miscible displacements. It was found that gravity segregation has an adverse effect on the results, and in the early stage of the displacement, unstable flow occurs for the injection rates studied. These rates are of the same order of magnitude as those considered by other experimenters. Increasing the length of the model, tends to have an over-all stabilizing effect on the results. For short slim-tubes, the usual indicators cannot be trusted to establish the MMP*. The use of longer slim-tubes yield the best estimate of the MMP. Introduction P. Deffrene et al.(1) have shown that the MMP is only dependent On the thermodynamic conditions (nature of the fluids and temperature), if proper care is taken to suppress any unstable phenomenon, namely, viscous fingering and gravity override. They used a vertical displacement, to take advantage of gravity segregation to suppress fingering, provided the rate used was smaller than the critical rate(2) defined as: Equation (Available In Full Paper) The criteria used for MMP estimation is to plot recovery versus operating pressure at gas breakthrough or after 1. to 1.2 pore volumes injection, and the pressure where the curve shows a clear break in slope, will correspond to the MMP. It is evident that the method will be influenced by the macroscopic sweep efficiency of the displacement making it imperative to eliminate the causes for poor sweep, which are: viscous fingering, and gravity override (horizontal systems). However, as pointed out by Orr et al(3), there is no general consensus as to the experimental procedures or the criteria defining the MMP. They observe that the displacement lengths range from 1.5 m to 25.6 m, flow geometries vary from vertical to flat coils to spirals, and flow velocities vary over nearly two orders of magnitude. The MMP is generally determined on criteria based on recovery at some pore volume injected and/or, on the visual observation of the transition zone in a sight glass. These criteria will be discussed in more detail in a later section. Our experiments were conducted on a flat slim-tube coil apparatus, because it is the most commonly used in the industry. The effect of tube length and injection rate on displacement efficiency, namely, recovery and shape of the effluent gas concentration profile, and consequently their effects on the criteria used for estimating the MMP were examined

Effects of Mobile Water on Multiple-Contact Miscible Gas Displacements

Abstract Miscible gas flooding using an alternate gas/water injection process (AGWIP) is presently being applied for enhanced oil recovery (EOR) in several waterflooded reservoirs.1–4 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 oil-displacement efficiency. Previous research on AGWIP has involved water-wet long-core flow tests using an injected solvent that is first-contact miscible with the in-place oil.5–13 Miscible floods employing CO2, enriched gas, methane, and flue gases, however, are rarely first-contact 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 water-and oil-wet conditions. Tests were conducted in 8-ft (244-cm) water- and oil-wet Berea cores in which CO2 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 CO2 is generating miscibility with the oil and mobilizing residual oil to waterflooding. Special emphasis is placed on understanding the effect of mobile-water saturation on the oil-displacement efficiency and the component transfer between phases necessary to develop miscibility in the CO2/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 effects 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.

CO2 Flood Performance Evaluation for the Cornell Unit, Wasson San Andres Field

Summary A numerical reservoir simulator has been used to predict CO2 enhanced oil recovery (EOR) performance for two process designs, either of which could be implemented at the Cornell Unit, Wasson San Andres field. The two CO2 displacement processes examined are a straight CO2 slug followed by continuous water injection, and a water-alternating-gas (WAG) process with CO2, followed by continuous water injection. Predicted recovery performances were found sensitive to viscous, capillary, and gravity-driven crossflow, as well as to reservoir stratification. Hence, evaluation of alternative process designs was influenced strongly by assumed values of effective vertical permeability within continuous pay intervals, even though the vertical permeability between major pay intervals is effectively zero. Work involving a no-crossflow stratification model of the Wasson pay suggested that a straight CO2 slug process would be preferable to a WAG process. On the other hand, work with a stratification model that allowed intrazone crossflow indicated that recovery could be improved significantly for a given size CO2 slug by means of a WAG process. Introduction Cornell Oil Co. and Markland Oil Corp. operate the Cornell Unit in the Wasson San Andres field, Yoakum County, TX. This 1,923-acre (7.7 x10 M) unit originally contained about 185 million STB (29.4 x 10 stock-tank m) oil. The property was unitized for supplemental recovery, and water injection began in mid-1965. Cumulative oil production before water injection was 18 million STB (2.9 x 10-6 stock-tank m3). As of Jan. 1982, secondary production was an additional 34 million STB (5.4X 10-6 stock-tank m3). A recent infill drilling program has treated a 35-acre (141 640-M) five-spot well configuration over the entire unit in preparation for a CO2 EOR project. This paper describes a numerical simulation study of alternative operating policies for CO2 injection in the Cornell Unit. CO2 Flood Simulator A CO2 flood simulator, using a finite-difference-based compositional model, was used in this study. The simulator was designed to reproduce the effects of major mass-transfer and phase-transport phenomena associated with CO2 EOR. For immiscible conditions, phase equilibria may be input to the simulator to represent EOR mechanisms of oil- phase swelling with condensed CO2 and vaporization (or extraction) of hydrocarbon fractions into the CO2-rich phase. Multiple-contact miscible (MCM) displacement may be represented explicitly with the program by incorporating appropriate phase equilibrium data. However, the philosophy of the modeling technique used in the program is to maintain segregated CO2- and oil-rich regions. By controlling the degree of segregation of these regions through the mixing parameter approach, we may represent the important phenomenon of viscous fingering, characteristic of highly unfavorable mobility ratio displacements, without describing the detailed structure of the unstable frontal advance. Local miscibility is determined by comparing computed pressure with miscibility pressure input to the program as a function of composition. This modeling technique represents miscible displacement and miscible/immiscible transition without describing the detailed compositional path required for explicitly representing MCM displacement. JPT P. 2271^

Compositional Model Studies – CO2 Oil-Displacement Mechanisms

Abstract 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°F. Three displacements at 120°F have been published by Metcalfe and Yarborough.1 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°F, three additional laboratory displacements were conducted at 150°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°F match the ex-perimental data and confirm the mechanistic understanding. The experimental and numerical results are in agreement with the minimum miscibility pressure theory of Yellig and Metcalfe.2 The results of this study confirm the importance of experimentally determined effluent compositional profiles and fully compositional models for CO2 mechanism studies.

The Effect of Phase Equilibria on the CO2 Displacement Mechanism

Abstract Carbon dioxide flooding under miscible conditions is being developed as a major process for enhanced oil recovery. This paper presents results of research studies to increase our understanding of the multiple-contact miscible displacement mechanism for CO2 flooding. Carbon dioxide displacements of three synthetic oils of increasing complexity (increasing number of hydrocarbon components) are described. The paper concentrates on results of laboratory flow studies, but uses results of phase-equilibria and numerical studies to support the conclusions.Results from studies with synthetic oils show that at least two multiple-contact miscible mechanisms, vaporization and condensation, can be identified and that the phase-equilibria data can be used as a basis for describing the mechanism. The phase-equilibria change with varying reservoir conditions, and the flow studies show that the miscible mechanism depends on the phase-equilibria behavior. Qualitative predictions with mathematical models support our conclusions.Phase-equilibria data with naturally occurring oils suggest the two mechanisms (vaporization and condensation) are relevant to CO2 displacements at reservoir conditions and are a basis for specifying the controlling mechanisms. Introduction Miscible-displacement processes, which rely on multiple contacts of injected gas and reservoir oil to develop an in-situ solvent, generally have been recognized by the petroleum industry as an important enhanced oil-recovery method. More recently, CO2 flooding has advanced to the position (in the U.S.) of being the most economically attractive of the multiple-contact miscibility (MCM) processes. Several projects have been or are currently being conducted either to study or use CO2 as an enhanced oil-recovery method. It has been demonstrated convincingly by Holm and others that CO2 can recover oil from laboratory systems and therefore from the swept zone of petroleum reservoirs using miscible displacement. However, several contradictions seem to exist in published results.. These authors attempt to establish the mechanism(s) through which CO2 and oil form a miscible solvent in situ. (The solvent thus produced is capable of performing as though the two fluids were miscible when performing as though the two fluids were miscible when injected.) In addition, little experimental work has been published to provide support for the mechanisms of multiple-contact miscibility, as originally discussed by Hutchinson and Braun.One can reasonably assume that the miscible CO2 process will be related directly to phase equilibria process will be related directly to phase equilibria because it involves intimate contact of gases and liquids. However, no data have been published to indicate that the mechanism for miscibility development may differ for varying phase-equilibria conditions.This paper presents the results of both flow and phase-equilibria studies performed to determine the phase-equilibria studies performed to determine the mechanism(s) of CO2 multiple-contact miscibility. These flow studies used CO2 to displace three multicomponent hydrocarbon mixtures under first-contact miscible, multiple-contact miscible, and immiscible conditions. Results are presented to support the vaporization mechanism as described by Hutchinson and Braun, and also to show that more than one mechanism is possible with CO2 displacements. The reason for the latter is found in the results of phase-equilibria studies. SPEJ P. 242

Effect of "Rich" Gas Composition on Multiple-Contact Miscible Displacement A Cell-to-Cell Flash Model Study

Abstract A cell-to-cell flash model was used to simulate the transition, or mixing, zone between a reservoir oil and several "rich" gases for multiple-contact miscible displacements. The transition-zone properties that control The oil recovery efficiency properties that control The oil recovery efficiency were determined and are junctions of the solvent concentration in the rich gas. Results indicate that the optimum use of solvent corresponds to a solvent concentration near the minimum enrichment level. Introduction Many papers have been published on the characteristics and applications of miscible displacement of oil with hydrocarbon fluids. The distinction is clearly made between first-contact miscible displacement, where the injected hydrocarbon fluid is miscible in all proportions with the oil, and multiple-contact miscible displacement, which occurs as a result of component transfer between hydrocarbon phases during flow in the porous media. Two general types of multiple-contact porous media. Two general types of multiple-contact miscible displacements are condensing gas or "rich" gas drive, and vaporizing or high-pressure gas drive. This paper concentrates on the rich gas drive, where the main feature is the transfer of intermediate components or solvent from the injected rich gas to the oil phase. The advantage of condensing gas drive in comparison with first-contact miscible displacement is the reduced concentration of the valuable solvent component in the injected hydrocarbon fluid. The effect of solvent concentration on the displacement process is an important factor in optimizing the use of solvent. Several studies have reported the use of compositional models to investigate the condensing gas drive process. These studies were useful in obtaining a better understanding of the component transfer between the liquid and vapor phases, and its effect on the transition zone existing between the injected hydrocarbon fluid and the reservoir oil. These studies did not define subzones within the transition zone or present methods to evaluate the properties of these subzones. A detailed numerical investigation of the effect of solvent concentration in the injected rich gas upon the behavior of the transition zone has not been reposed previously. The purpose of this work is to obtain this information, which then can be applied to the simulation of reservoir performance and the design of laboratory experiments. performance and the design of laboratory experiments. A cell-to-cell flash model described by Metcalfe et al. was used in this study. OBJECTIVES The principal objective of this study is to present a method that can be used to investigate the physical properties of the transition zone existing between properties of the transition zone existing between the rich gas and the reservoir oil in miscible displacements. Only the effect of rich gas composition on these physical properties will be demonstrated. However, the method allows investigation of the effect of other variables, such as relative-permeability characteristics, pressure, and the composition of the reservoir oil. Knowledge of the physical properties of the transition zone is considered a first step toward proper design of rich gas, multiple-contact oil proper design of rich gas, multiple-contact oil recovery methods. Additional studies are necessary for the design. Though these studies are mentioned within the paper, they are beyond the scope of this work. DESCRIPTION OF STUDY The study involved simulating the displacement of a reservoir oil with five different rich gases. The composition and properties of the fluids are given in Table 1. The reservoir temperature was 231 degrees F and the reservoir pressure was 2,250 psia for all simulations. The cell-to-cell flash model with the "phase mobility option" was used to simulate the oil recovery method. One hundred cells were used. The phase mobility option uses phase mobilities, (kr/) phase, to determine the relative volume of each phase flowing from a particular cell. SPEJ P. 310

The Effects of Water Injection on Miscible Flooding Methods Using Hydrocarbons and Carbon Dioxide

Abstract The effects of mobile water saturations on oil recovery and solvent requirements were studied in miscible displacement tests on sandstone cores. it was found thatoil, if trapped by mobile water, cannot be easily contacted by solvent, and the amount of oil is directly related to measurable relative-permeability characteristics;miscible displacement Performances for secondary and tertiary conditions are equivalent;long-core tests describe the movement of fluid banks that would occur in field floods; andflooding response for solvent developed from multiple contact of crude oil with carbon dioxide or rich gas in long cores is the same as that for liquid solvents with first-contact miscibility. Introduction Miscible flooding is receiving increasing interest as a means of recovering tertiary oil left after waterflooding. Mobile water is a factor in tertiary flooding, and can also be a factor in secondary operations where alternate water and solvent injection is used to improve the low sweep efficiency of miscible flooding with hydrocarbon and acid gases. Several publications have reported a reduction in displacement efficiency when mobile water is present at the displacement front. Stalkup present at the displacement front. Stalkup summarized this information and also reported increased mixing caused by the mobile water. However, more information is needed to implement recovery operations where mobile water conditions can occur. The purpose of this paper is to provide information about the displacement behavior in those portions of a reservoir that may contain a high water saturation and that are contacted by a solvent. Factors examined arethe relationship of oil trapping by water to relative permeability and wettability,the development and growth of fluid banks,a comparison of first-contact and multiple-contact miscible displacement, before and after waterflooding,the effect of flow rate and system length on multiple-contact miscible displacement, andthe displacement of oil by the simultaneous injection of solvent and water. The experiments performed were in laboratory cores and are not scaled to field conditions in some respects. The study provides insight into some of the pertinent mechanisms of the displacement process rather than data that is directly applicable to a field situation. MATERIALS AND PROCEDURE OIL-TRAPPING TESTS Drainage and imbibition water-oil relative-permeability data were obtained on a water-wet Berea sandstone core using the steady-state test procedure. The dimensions of the Lucite-encased Berea core are given in Table 1. Two series of first-contact miscible-displacement test, one series involving the displacement of water and the other involving the displacement of oil, were performed at various levels of oil and water saturation on the same core. Saturations during the relative-permeability tests and miscible - displacement tests were determined using an X-ray absorption technique. The recovery performance was calculated by refractive index analyses of the produced fluids. To provide for these analyses, two bones and two refined oils were prepared for the tests. TABLE 1 - TRAPPING-ENVELOPE MISCIBLE-DISPLACEMENT TESTS, 2.1-IN.-DIAMETER BY 5.1-IN.-LONG BEREA SANDSTONE CORE Residual In-Place Saturation Solvent Liquid Test Flowing percent PV Flow Rate Saturation Number WOR Oil Water (PV/hour) (percent PV) ------ ------- --- ----- --------- ------------- Drainage Tests - 1.0-cp Nal brine displace by 0.95-cp brine D-1 oo 0 100 2.84 0 D-2 2 29 71 1.79 0 D-3 0.1 45 55 0.284 0.5 Imbibition Tests - 1.48-cp oil displaced by 1.42-cp oil containing iodobenzene I-1 0 74 26 2.85 0 I-2 0.2 43 57 2.28 7 I-3 1 34 66 0.78 13 I-4 5 32 68 2.72 17 I-5 1 35 65 1.21 10 SPEJ P. 217