Multicontact Miscible Displacement Research Articles

Оценка влияния попутного нефтяного газа с высоким содержанием диоксида углерода на режим вытеснения нефти при разработке Толумского месторождения

Depending on reservoir conditions, composition of reservoir oil and gas agent, various modes of oil displacement by gas can be implemented in reservoir conditions. The most preferable mode from the standpoint of the completeness of oil recovery is the mode of miscible displacement of oil by gas. The main parameter indicating the achievement of the miscible displacement mode is the minimum miscibility pressure. The most popular and reliable laboratory method for determining the minimum mixing pressure is the slim-tube method. The results of laboratory studies performed to determine the value of the minimum miscibility pressure of reservoir oil from the Tolumskoye field and associated petroleum gas of the Semividovskaya group of fields and also to determine the mode of oil displacement by associated petroleum gas are presented. To determine the parameters of reservoir oil and change its properties at various molar concentrations, the standard PVT research technique was used. To determine the minimum miscibility pressure, the slim-tube technique was used. To assess the mechanism of miscibility process development, chromatographic analysis of the sampled gas composition and visual analysis of the phase fluids behavior by means of a visual cell were additionally performed. Two series of filtration experiments were performed to displace the recombined oil model of the Tolumskoye field by the model of associated petroleum gas from the Semividovskaya group of fields on slim models. According to the obtained dependence of the oil displacement coefficient on pressure, when oil from the Tolumskoye field was displaced by associated petroleum gas of the Semividovskaya group of fields, the minimum miscibility pressure would be 14.8 MPa. Based on the criteria for determining the mixing mode, as a result of generalization and comprehensive analysis of the research results, it was found that for the conditions of the Tolumskoye field, the mode of oil displacement by associated petroleum gas of the Semividovskaya group of fields was the mode of the developed multi-contact miscible displacement (the mechanism of condensation of solvent components into the oil phase).

A new correlation for predicting the minimum miscibility pressure regarding the enhanced oil recovery processes in the petroleum industry

ABSTRACTMiscible gas injection is a promising technique to enhance the oil recovery from petroleum reservoirs. Natural gas is usually injected because of consistency between the gas and reservoir fluid composition and accessibility of the injected fluid. In this work a new correlation is presented for accurate prediction of the required minimum miscibility pressure (MMP) for multicontact miscible displacement of reservoir petroleum by hydrocarbon gas injection. Accurate estimation of the MMP is required for optimal design of recovery systems and optimization of the production economics. It is shown that the presented correlation is very accurate and reliable for predicting the MMP over wide ranges of oil and gas compositions. Comparison of the suggested correlation with the most important existing correlations shows that the presented correlation outperforms the other alternatives both in accuracy and generality.

New Correlation for Calculation of Hydrocarbon Gas Minimum Miscibility Pressure (MMP) Using Wide Experimental Data

The authors present a new empirically derived correlation for estimating the minimum miscibility pressure (MMP) required for multicontact miscible (MCM) displacement of reservoir petroleum by hydrocarbon gas flooding. Only few empirical correlations exist for determining the MMP. These correlations are often used to estimate the MMP without considering the composition of the injected gas. On the other hand these correlations are based on a limited set of experimental data, which are not quite applicable. In addition, in such correlations the complex condensing/vaporizing displacement process is not regarded. In this study, however, the derived correlation investigates the influence of the vaporizing/condensing drive mechanism and oil and gas composition on gas miscibility pressure. MMP has been correlated with temperature, oil composition, and injection gas composition. Their effect on hydrocarbon gas MMP has been documented by using sensitivity analysis by slim tube experimental data. The new correlation is based on regression of widely experimentally measured MMP data in literature and data derived from slim tube experiment in this study. By comparing the calculated MMPs from the improved correlation data with currently used correlations and experimentally measured data, it was found that the new correlation is significantly more accurate than other correlations.

Tie-Line-Based K-Value Method for Compositional Simulation

Summary The thermodynamic behavior of multicomponent multiphase systems is highly nonlinear, and the coupling to the flow equations is quite complex; as a result, equation-of-state (EOS) -based simulations can be computationally prohibitive. We describe a new K-value method that captures the compositional dependence of the phase behavior. Specifically, we propose a method for selecting compositions used in the tabulation of K-values and define an operator that interpolates the K-values as a function of pressure and composition. The method employs the minimal critical pressure (MCP) to detect supercritical compositions, which allows for effective modeling of multicontact miscible displacements. We compare our K-value approach with standard EOS compositional simulation for several isothermal problems, and we demonstrate the efficiency and accuracy of the proposed method.

Mixing and Mass Transfer in Multicontact Miscible Displacements

In this work, we investigate the accuracy of some physical models that are frequently used to describe and interpret dispersive mixing and mass transfer in compositional reservoir simulation. We have designed a quaternary analog fluid system (alcohol–water–hydrocarbon) that mimics the phase behavior of CO2-hydrocarbon mixtures at high pressure and temperature. A porous medium was designed using PolyTetraFlouroEthylene (PTFE) materials to ensure that the analog oil acts as the wetting phase, and the properties of the porous medium were characterized in terms of porosity, permeability and dispersivity. Relative permeability and interfacial tension (IFT) measurements were also performed to delineate interactions between the fluid system and the porous medium. The effluent concentrations from two-component first-contact miscible (FCM) displacement experiments exhibit a tailing behavior that is attributed to imperfect sweep of the porous medium: A feature that is not captured by normal dispersion models. To represent this behavior in displacement calculations, we use dual-porosity (DP) models including mass transfer between flowing and stagnant porosities. Two 4-component two-phase displacement experiments were performed at near-miscible and multicontact miscible (MCM) conditions and the effluent concentrations were interpreted by numerical calculations. We demonstrate that the accuracy of our displacement calculations relative to the experimental observations is sensitive to the selected models for dispersive mixing, mass transfer between flowing and stagnant porosities, and IFT scaling of relative permeability functions. We also demonstrate that numerical calculations substantially agree with the experimental observations for some physical models with limited need for model parameter adjustment. The combined experimental and modeling effort presented in this work identifies and explores the impact of a set of physical mechanisms (dispersion and mass transfer) that must be upscaled adequately for field-scale displacement calculations in DP systems.

The influence of high permeability lenses on immiscible, first- and multi-contact miscible gas injection

The recovery of oil by injection of miscible gas has been a subject of interest and research in petroleum engineering over the past 40 years. In a first contact miscible displacement, the injected fluid forms only single-phase mixtures with oil in place, so in theory, 100% recovery can be achieved. Unfortunately, many phenomena conspire to limit the efficiency of the miscible flooding process including viscous fingering and permeability heterogeneity. One type of important heterogeneities that occur at the small scale is the lensed system. This is one of the most common sedimentary structures found in sandstone reservoirs and is almost universal. This paper investigates the physics of gas–oil multi-contact miscible (MCM) displacements within lensed porous media using a combination of well-characterised laboratory experiments and detailed numerical simulation. The aims were to: (1) quantify the recovery efficiency of MCM displacements conducted at different flow conditions, (2) provide a set of benchmark experimental data for MCM displacements performed within lensed porous media, and (3) validate conventional compositional simulation of MCM displacements. The novel experimental studies were conducted in specially designed lens visual models packed with unconsolidated glass beads and used a two-phase three-component (IPA/water/cyclohexene) liquid system that exhibits an upper critical point at ambient conditions. First contact miscible (FCM), immiscible and MCM displacement experiments were performed. They were then simulated using a commercial compositional simulator with a single set of EOS parameters and without using history matching (all input data to the simulator were determined from independent experiments). The produced oil and gas in the experiments were found not to be in compositional equilibrium. This was observed in both homogeneous (as reported previously by Al-Wahaibi et al., 2005) and lens models. This indicates that nonequilibrium occurs at even smaller scales than the lensed structure. As a result, the oil recoveries and gas cuts predicted by compositional simulation for MCM displacements differed significantly from the experimental results, although an excellent match was obtained for the FCM and immiscible displacements. Further experiments investigating the effects of varying injection rates and gravity forces on the level of nonequilibrium observed in the produced fluids are described. Numerical simulation of these experiments provides additional insight into the physical mechanisms causing the nonequilibrium. The experiments performed in this study are the first of their kind as they report the significance of nonequilibrium on MCM process prediction and the influence of lens heterogeneities on MCM injection. This study has important implications for the correct interpretation of core data, and for scale-up processes to reservoir scale, particularly for handling gas/oil nonequilibrium when modelling MCM displacements.

Effect of initial gas saturation on miscible gasflood recovery

Multi-contact miscible (MCM) displacements are designed to achieve piston-like flow and optimal recovery of in-situ hydrocarbons. The primary goal of this paper is to explore the ramifications of leading condensate or gas banks in MCM floods with two-phase initial conditions, a problem which has not been considered in detail in theoretical or experimental research. The consequences of two or more in situ phases may be significant for displacements in capillary transition zones, vertically-graded compositional reservoirs or gas condensate reservoirs. We develop method of characteristics (MOC) solutions for 1-D displacement of two-phase initial compositions by gases that are enriched below and above the minimum miscibility enrichment (MME). We consider ternary and quaternary systems to examine both condensing and condensing/vaporizing (C/V) mechanisms. In the MCM displacements considered, recoveries are dependent on relative permeability functions and can be adversely affected by two-phase initial reservoir fluids for injection times less than 1.0 pore volumes injected (PVI). The delay in heavy component recovery could significantly impact the economics of gas injection projects. Because flow is MCM, however, recovery increases rapidly to 100% at 1.0 PVI in all cases.

Oil Recovery Mechanisms via Multicontact Miscible Gas Injection Process within Lensed Systems

The experiments performed in this study are the first of their kind as they report the significance of nonequilibrium on gas-oil multicontact miscible (MCM) process prediction and the influence of lenses' heterogeneities on MCM injection. This was achieved using a combination of well-characterized laboratory experiments and detailed numerical simulation. Particularly, the aims were to (a) quantify the recovery efficiency of MCM displacements conducted at different flow conditions, (b) provide a set of benchmark experimental data for MCM displacements performed within lensed, porous media, and (c) validate conventional compositional simulation of MCM displacements. The novel experimental studies were conducted in specially designed lenses visual models packed with unconsolidated glass beads and used a two-phase, three-component (Isopropyl alcohol [IPA]/water/cyclohexene) liquid system that exhibits an upper critical point at ambient conditions. First contact miscible (FCM), immiscible, and MCM displacements were performed under different flow conditions. They were then simulated using a commercial compositional simulator without using history matching. The produced oil and gas in the experiments were found not to be in compositional equilibrium. Consequently, the oil recoveries and gas cuts predicted by compositional simulation for MCM displacements differed significantly from the experimental results, although an excellent match was obtained for the FCM and immiscible displacements.

Gas–oil non-equilibrium in multicontact miscible displacements within homogeneous porous media

This paper investigates the non-equilibrium observed between the compositions of the produced phases in a series of multi-contact miscible displacements performed in the laboratory. These used a two-phase, three-component (Isopropyl alcohol/water/cyclohexene) liquid system that exhibits an upper critical point at ambient conditions. Both vaporising and condensing drives were performed in well-characterised homogenous glass-bead packs. The use of analogue fluids and bead-packs enabled visualisation of the displacements as well as the usual measurements of effluent composition against time and recovery. Non-equilibrium was observed in the effluent from both the condensing and vaporising experiments. This increased with flow-rate but appeared to be independent of the permeability and the length of the bead-pack. Further experiments investigating the influence of gravity on vertical displacements indicated that non-equilibrium may also be a function of the viscous to gravity ratio. Detailed simulation using a commercial compositional simulator was unable to predict this non-equilibrium unless the results were tuned to the experimentally observed effluent profiles using alpha factors. This is despite the fact that all PVT data, relative permeabilities and other pack properties were taken directly from the experiments. However good results were obtained from a layered model with the permeability distribution previously adjusted to match effluent data from a unit mobility ratio miscible displacement in the same pack. These results are consistent with physical dispersion being the underlying cause of the non-equilibrium. Viscous fingering was discounted due to the low mobility ratio (~ 2) of the displacements.

Four-Component Gas/Water/Oil Displacements in One Dimension: Part III, Development of Miscibility

The structure of the system of conservation laws in fully compositional three-phase, four-component flow is examined for the first time. Two of the eigenvalues can be found analytically for this flow regime, regardless of the equation of state used to model the phase behavior. A cubic equation of state is used to calculate the gas/oil phase behavior and Henry’s law is used to represent the partitioning of hydrocarbons between the hydrocarbon and water phases. Sample analytical solutions are found for Riemann problems modeling the injection of carbon-dioxide and water into an oil reservoir. Finally, the structure of the solutions at the minimum miscibility pressure (MMP) for the hydrocarbon system is studied. We show that when water is injected simultaneously with gas at the MMP, multicontact miscible displacement of the oil by the injected gas develops only if the fraction of water in the injected fluid is below a critical value. For water fractions above the critical value, water flowing at a high velocity forces the composition path of the solution to remain in the three-phase region in which two hydrocarbon phases are present. We study both condensing and vaporizing gas drives to demonstrate that this result is general.

Experimental and Numerical Studies of Gas/Oil Multicontact Miscible Displacements in Homogeneous and Crossbedded Porous Media

Summary We investigate oil recovery from multicontact miscible (MCM) gas injection into homogeneous and crossbedded porous media, using a combination of well-characterized laboratory experiments and detailed compositional flow simulation. All simulator input data, including most EOS parameters, were determined experimentally or from the literature produced fluids in all experiments were found not to be in compositional equilibrium. This was not predicted by the simulator, giving a poor match between experimental and simulated oil recoveries. The match was significantly improved for the cross-bedded displacements by using alpha factors derived from the MCM displacements in the homogeneous pack. Introduction The recovery of oil by miscible gas injection has been a subject of interest and research in petroleum engineering for more than 40 years (Stalkup 1983). In a first-contact, miscible (FCM) displacement, the gas and oil mix instantly in all proportions. No capillary forces exist, so, in principle, residual oil saturation is zero, and 100% oil recovery should be achieved. In practice, many phenomena conspire to limit the efficiency of the miscible flooding process, including viscous fingering, gravity override, and permeability heterogeneity. Moreover, it is often not economical, and sometimes not technically feasible, to inject a gas that is first-contact miscible with the oil. Instead, the injected gas is designed to develop miscibility with the oil by mass transfer during the displacement. This is a so-called MCM gas injection. If the bulk of the mass transfer is from the gas to the oil, then the displacement is termed a condensing drive. If most of the mass transfer is from the oil to the gas, then it is termed a vaporizing drive. In most cases, however, because of the multicomponent nature of oil and gas, the mass transfer is actually a mixture of both these cases, and the displacement is termed a condensing-vaporizing drive. Small-scale heterogeneities can have a significant impact on recovery efficiency (Jones et al. 1995; Jones et al. 1994; Kjonsvik et al. 1994), yet they cannot be modeled explicitly in field-scale simulations. Some of the most common small-scale heterogeneities found in sandstone reservoirs are laminations. However, because laminations have a small size and are generally at an angle to the principal flow direction, their influence onfluid flow is one of the most difficult features to predict numerically. There is a significant amount of literature describing systematic investigations of first-contact miscible and immiscible displacement processes in laminated sandstones (Huang et al. 1995, 1996; Ringrose et al. 1993; Kortekaas 1985; Honarpour et al. 1994; Hartkamp-Bakker 1991, 1993; McDougall and Sorbie 1993; Marcelle-DeSilva and Dawe 2003; Borresen and Graue 1996; Roti and Dawe 1993; Dawe et al. 1992; Caruana and Dawe 1996; Caruana 1997). Both experimental and simulation studies show that significant volumes of oil can be trapped by capillary forces during immiscible displacements (Huang et al. 1995, 1996; Ringrose et al. 1993; Kortekaas 1985; Honarpour et al. 1994; Hartkamp-Bakker 1991, 1993; McDougall and Sorbie 1993; Marcelle-DeSilva and Dawe 2003; Borresen and Graue 1996; Roti and Dawe 1993; Dawe et al. 1992; Caruana and Dawe 1996; Caruana 1997). However, the influence of these heterogeneities on MCM displacements, during which capillary forces change from being very significant when gas is first injected to negligible once miscibility has developed, has not yet been investigated. Indeed, the only comparisons of well-characterized MCM displacement experiments and detailed simulations reported in anywhere in the literature are those of Burger and colleagues (Burger and Mohanty 1997; Burger et al. 1996; Burger et al. 1994).

Rapid Flash Calculations for Compositional Simulation

Summary The computational time for conventional flash calculations increases significantly with the number of components, making it impractical for use in many fine-grid compositional simulations and other applications. Previous research to increase flash-calculation speed has been limited to those with zero binary interaction parameters (BIPs) or approximate methods based on an eigenvalue analysis of the binary interaction matrix. Practical flash calculations, however, nearly always have some nonzero BIPs. Further, the accuracy and speed of the eigenvalue methods varies depending on the choice and number of the dominant eigenvalues. This paper presents a new and simple method for significantly increasing the speed of flash calculations for any number of nonzero BIPs. The approach requires the solution of up to six reduced parameters regardless of fluid complexity or the number of components and is based on decomposing the BIPs into two parameters using a simple quadratic expression. The new approach is exact in that the equilibrium-phase compositions for the same BIPs are identical to those with the conventional flash calculation; no eigenvalue analysis is required. Further, the new approach eliminates the Rachford-Rice procedure (1952) and is more robust than the conventional flash-calculation procedure. We demonstrate the new approach for several example fluids and show that speedup by a factor of approximately 3 to 20 is obtained over conventional flash calculations, depending on the number of components. Introduction Gas injection into oil reservoirs results in complex interactions of flow with phase behavior that often are not modeled accurately by black-oil simulation. This is especially true for miscible or nearly miscible floods in which significant mass transfer occurs between the hydrocarbon phases. Such floods are best modeled by compositional simulation. A significant disadvantage of compositional simulation, however, is that it is much more computationally intensive than black-oil simulation. The primary reason for the increased computational time is the result of solving repeated flash calculations with cubic equations of state (EOS). Research has shown that EOS flash calculations can occupy 50 to 70% of total computational time in compositional simulations (Stenby and Wang 1993; Chang 1990). This is also true for other applications, such as multiphase flow in pipelines. The use of fewer pseudocomponents can reduce the flash computation time, but fewer components results in less accuracy (Hong 1982; Liu 2001; Egwuenu et al. 2005). This is especially true in multicontact miscible displacements, in which miscibility is developed by a combined condensing/vaporizing drive process (Zick 1986; Johns et al. 1993; Egwuenu et al. 2005). Fluid characterization by pseudocomponent models can be improved by tuning to the analytical minimum miscibility enrichment or minimum miscibility pressure (Johns et al. 1994), but those models still require significant computational time, even for fewer pseudocomponents. Another way to reduce computation time is to reduce the number of gridblocks. With coarse grids, however, numerical dispersion is large, which may cloud the results (Solano et al. 2001). Ideally, fine grids should be used that better match the level of dispersion found at the field scale. More recently, methods have been examined to find reduced parameters for flash calculations. Michelsen (1982a, 1982b, 1986) significantly increased flash-calculation speed by finding three reduced parameters, regardless of the number of components. His method, however, assumes zero BIPs, which is too restrictive for real fluid characterization. Michelsen also gave a practical method for stability calculations using the tangent plane distance (TPD) (Michelsen 1982b).

Drainage and imbibition relative permeabilities at near miscible conditions

The changes in gas and oil relative permeabilities as miscibility is approached are of particular importance in multi-contact miscible displacements. These changes are a function of the detailed phase behaviour of the fluids and their physical properties as well as the properties of the porous medium itself. In this work, we investigate the behaviour of two-phase drainage and imbibition relative permeability curves of four, different, equilibrated fluid pairs from a three component, two-phase system (cyclohexene, isopropyl alcohol and water) that exhibits a critical point at ambient conditions. The tie-lines of these fluid pairs are at varying distances from the system's critical point. Equilibrium phase compositions and interfacial tensions (IFT) were determined for each of the four fluid pairs. Dynamic displacements were then performed in a linear two dimensional, bead-pack. Unsteady state, drainage and imbibition relative permeabilities were determined for the various pre-equilibrated mixtures. The experimental results show a clear change in relative permeability as the fluid pairs approach the critical point. As the interfacial tension decreases the non-wetting phase relative permeability increases more rapidly than the wetting phase relative permeability and hysteresis becomes less important. Two correlations [Coats, K.H., 1980. An equation of state compositional model: SPE J, 20 (5): 363-376.; Whitson, C.H., and Fevang, Ø., 1997. Generalized pseudo pressure well treatment in reservoir simulation. In Proc., IBC Conference on Optimization of Gas Condensate Fields.], commonly used to model the changes in relative permeability with interfacial tension, and the development of miscibility, were compared with the experimental data. The Coats correlation, which uses a single adjustable parameter to model the changes in both relative permeabilities and residual oil saturation as a direct function of the IFT, yielded an unacceptable match to the experimentally determined fractional flow. However the Whitson–Fevang correlation, which relates the changes in relative permeability to the capillary number using two adjustable weighting functions, presents a satisfactory match.

Pt. McIntyre: A Case Study of Gas Enrichment Above MME

Summary Pt. McIntyre field operates an enriched-gas-injection scheme that displaces oil in a multicontact miscible (MCM) displacement achieved through a combined condensing/vaporizing (C/V) mechanism. A range of miscible-injectant (MI) compositions, varying from the minimum miscible enrichment (MME) to substantially above the MME, is available to the project. Field-scale numerical-simulation studies for the Pt. McIntyre field show that incremental oil recovery is nearly doubled when using the richest available MI composition. At the MME, dispersion can act to substantially reduce oil recovery by reducing the concentration of enriching components in the near-miscible zone. Increasing enrichment above the MME compensates for this action. Accurate predictions of incremental oil depend on the numerical dispersion in a simulator being able to match the impact of physical dispersion. We show how compositional core data from an MI-swept interval provide confirmation of the impact of dispersion at field scale and demonstrate the appropriateness of the simulation model. The benefit of enrichment appears to be robust to the variation of reservoir description found at Pt. McIntyre and to whether the MI application targets incremental oil through liquid- or vapor-phase recovery. Previous studies into MI enrichment have reported that for a four-component system, the mechanism changes from C/V to purely condensing as the enrichment level approaches first-contact miscibility (FCM). We show that with the addition of a small amount of heavy component, the C/V behavior is retained with increasing enrichment until transition into FCM. This makes it unlikely that a transition to a purely condensing mechanism will occur in real reservoirs.

Theory of Multicontact Miscible Displacement with Nitrogen

Abstract Solutions obtained by the method of characteristics (MOC) for displacement of mixtures of methane, butane and decane by nitrogen or nitrogen/methane mixtures are used to explain conflicting experimental observations concerning the sensitivity of minimum miscibility pressures to changes in the compositions of an initial oil or the injection gas. The solutions presented show why some investigators have reported weak dependence of the minimum miscibility pressure (MMP) on methane concentrations while others have reported significant sensitivity. The analysis of displacement composition routes indicates that either observation can be correct for some ranges of initial and injection fluid compositions, and shows that the sensitivity behavior depends on the relative positions in composition space of three key tie lines (the initial, injection, and crossover tie lines) with respect to the critical locus.

Miscible Gas Displacement of Multicomponent Oils

Summary This paper extends the theory of multicontact miscible displacements in four-component systems to displacements by a single gas component of an oil containing any number of components. Multicomponent solutions are developed using the method of characteristics in the absence of dispersion and are shown to consist of a series of successive pseudoternary displacements. Example analytical solutions are constructed and compared to experimental results for a synthetic ten-component oil displaced by CO2 as given by Metcalfe and Yarborough1. The minimum pressure for miscibility (MMP) for the synthetic oil is determined to be substantially below pressures used in the experiments and is below the bubble-point pressure. We show that multicontact miscibility (MCM) can be achieved even when an oil exists as two phases. The displacement of the synthetic oil by CO2 is demonstrated to have features of both condensing and vaporizing mechanisms (C/V). Furthermore, the key tie line that controls development of miscibility is the crossover tie line that divides the condensing and vaporizing portions of the displacement path (composition route). Extension of the theory for displacements of real oils with an arbitrary number of components is also discussed. For displacements by CO2 of an oil that contains only methane (CH4), ethane (C2) and heavier components, we demonstrate that the most downstream crossover tie line will control the development of miscibility. For displacements by the most volatile component (i.e. pure N2 or CH4 injection) of the same oil, however, displacements are purely vaporizing and miscibility is controlled by the tie line that extends through the oil. A comparison of the component volatilities of the oil relative to the injection gas determines which one of the tie lines will control the development of miscibility. A procedure is given that can be used to find the key tie line that controls miscibility and also to estimate the MMP from an equation-of-state (EOS).

A Correlation for Miscible Flood Displacement Efficiency in the San Andres With NMR Relaxation

ABSTRACT A set of San Andres crystalline dolomite cores was examined for the relationship between pore attributes discernible from NMR relaxation and miscible flooding displacement efficiency. A strong correlation was observed between the inferred abundance of long relaxation time components and laboratory measured residual oil to a multicontact miscible displacement process. NMR relaxation time distribution proved to be a simple, noninvasive, nondestructive indicator of flow performance in the 12 San Andres dolomite samples examined. Spin-lattice relaxation measurements were conducted on clean, brine saturated core end pieces from plugs taken adjacent to those used for flow displacement studies. Sample data were deconvoluted into a distribution of relaxation times, which is intimately related to surface-to-volume ratio distribution. The median relaxation time was determined to be the most sensitive statistic to convey flow performance. Residual oil saturation was adequately represented by a power law function of the median relaxation time. Relaxation time is recognized to be a function of pore size, shape, surface roughness, and mineral composition. It was determined through direct observation by scanning electron microscopy that variation between samples was principally due to pore size distribution. Samples with larger mean pore size were observed to be less efficiently swept. Larger pores within a distribution are envisioned to bias individual fluid flow pathways, causing significant stranding of oil.

The effect of reservoir heterogeneity on the performance of unstable displacements

We investigated the effects of reservoir heterogeneity on immiscible, first-contact miscible and multicontact miscible displacements in laboratory scale systems by numerical reservoir simulation. Several two-dimensional heterogeneous permeable media were generated geostatistically and systematically characterized by Dykstra-Parsons coefficient and dimensionless correlation length. The Dykstra-Parsons coefficient and the dimensionless correlation length were varied over wide ranges to cover the conditions normally encountered in petroleum reservoirs and to study their interactions on the performance of unstable displacements. We found that heterogeneity was always detrimental to the recovery performance. The severity of this detrimental effect increased with an increase in the Dykstra-Parsons coefficient and an increase in the correlation length. This detrimental effect of heterogeneity could also be seen in the saturation maps, which showed significantly different fingering patterns for different permeability distributions. These maps also showed fundamental differences in the nature of immiscible, first-contact miscible, and multicontact miscible displacements. First-contact miscible displacements were the most efficient, immiscible displacements were the least efficient, and multicontact miscible displacements were intermediate between the two.

Miscibility and Miscible Displacement

Technology Today Series articles provide useful summary informationon both classic and emerging concepts in petroleum engineering. Purpose:To provide the general reader with a basic understanding of a significantconcept, technique, or development within a specific area of technology. Summary Miscible displacement has been developed as a successful EORprocess in the past 25 years. Two types of miscible displacement exist: processin the past 25 years. Two types of miscible displacement exist: first-contactand multicontact miscible displacement. An understanding of the definition ofmiscibility and how injected fluids react with reservoir fluids is necessary tounderstand these processes. Miscibility Through research over the past 25 years, miscible-phase displacementprocesses that use certain gases as injectants have been developed assuccessful means for increasing oil recovery from many reservoirs. Tounderstand these processes it is first necessary to provide a definition of"miscibility," particularly as provide a definition of "miscibility,"particularly as distinguished from "solubility." Solubility is defined as theability of a limited amount of one substance to mix with another substance toform a single homogeneous phase. Miscibility is defined as the ability of twoor more substances to form a single homogeneous phase when mixed in allproportions. For petroleum reservoirs, miscibility is defined as that physicalcondition between two or more fluids that will permit them to mix in allproportions without the existence of an interface. If two fluid phases formafter some amount of one fluid is added phases form after some amount of onefluid is added to others, the fluids are considered immiscible. An interfacialtension (IFT) exists between the phases when they are immiscible. When asubstantial IFT (greater than 0.1 dynes/cm) exists between phases in a porousmedium, capillary forces prevent the complete porous medium, capillary forcesprevent the complete displacement of one of those phases by the other. Asubstantial residual oil saturation remains in a porous medium after aninjected immiscible fluid is used to displace oil from the medium, as inwaterflooding. Figs. 1 and 2 illustrate the differences between immiscible andmiscible conditions for certain fluids. Miscible Displacement Miscible displacement implies that with the IFT between the oil anddisplacing fluid eliminated (IFT=O), the residual oil saturation will bereduced to zero in the swept region. There are basically two types of miscibledisplacements: first contact and multicontact. The term first contact meansthat and, amount of the solvent can be injected and will exist as a singlephase with the oil in the reservoir. Low-molecular-weight hydrocarbonssuch aspropane, butane, or mixtures of liquefiable petroleum gas (LPG)or heavierhydrocarbonssuch as gasoline fractionshave been used as solvent forfirst-contact miscible flooding. In practice, solvents for first-contactmiscibility are usually too expensive for continuous injection. Instead, attempts have been made to inject a limited solvent volume, or slug, whichconceptually can be miscibly displaced with a less expensive fluid, such asmethane, nitrogen, or flue gas. This chase fluid, in turn, is immisciblydisplaced by water, leaving a residual saturation of the chase fluid. Multicontact or dynamic miscible displacements are of two mechanistic types:vaporizing-gas drive and condensing-gas drive. In the vaporizing-gas-driveprocess, a lean gas (i.e., methane. nitrogen, or flue process, a lean gas(i.e., methane. nitrogen, or flue gas) is injected, and as it travels throughthe reservoir, it vaporizes methane through LPG components from the reservoiroil. When the leading edge of the displacing gas front has vaporized sufficienthydrocarbons, it becomes miscible with virgin reservoir fluid. A similarmechanism occurs when CO2 is injected as liquid or critical fluid. However, highly compressed CO2 extracts heavier (gasoline-range) hydrocarbons from thereservoir oil, which allows the displacement front to become miscible at lowerpressures than those required for the lean gas. In the condensing-gas-driveprocess, an enriched gas (containing hydrocarbons heavier than methane) isinjected, and as it travels through the reservoir, it gives up heaviercomponents to the oil. When the oil becomes sufficiently enriched, it becomesmiscible with freshly injected enriched gas. Both types of multicontactmiscible displacements require a transfer of hydrocarbon components between theinjected and the reservoir fluid under dynamic conditions. Measurement of Miscible Fluid Conditions Miscibility between the reservoir oil, solvent, and gas is a function of thecomposition of these fluids and the pressure and temperature in the reservoirduring the displacement process. At a given reservoir temperature, the pressurerequired to achieve miscible displacement can be estimated from publishedcorrelations. First-contact miscibility can be determined experimentally with ahigh-pressure visual cell. The reservoir oil and solvent are combined in thecell at reservoir temperature. First-contact miscibility is achieved at thepressure when the interface between the fluids disappears. P. 817

Generalized Minimum Miscibility Pressure Correlation

Abstract This paper presents a generalized correlation for predicting the minimum miscibility pressure (MMP) required for multicontact miscible displacement of reservoir fluids by hydrocarbon, CO2, or N2 gas. The equations are derived from graphical correlations given by Benham et al.1 and give MMP as a function of reservoir temperature, C7+ molecular weight of the oil, mole percent methane in the injection gas, and the molecular weight of the intermediates (C2 through C6) in the gas. CO2 and N2 are represented in the current correlation by "equivalent" methane/propane- and methane/ethane-mixture injection gases, respectively. The study shows that for hydrocarbon systems, paraffinicity has an effect on MMP. In the equations, the C7+ molecular weight of the oil is corrected to a K factor of 11.95, thereby accounting for varying paraffinicity. An additional temperature effect on N2 MMP is related to the API gravity of the oil. The N2 correlation, however, is not tested against measured MMP data other than those used to develop the equation and should be used with care. A correlation that accounts for the additional effect on CO2 MMP caused by the presence of intermediate components in the reservoir oil is presented. Predicted MMP's from the correlations developed are compared to experimental slim-tube displacement data from the literature arid from our displacement tests on North Sea gas/oil systems. These displacement tests have been performed with a packed slim tube, where the effect of viscous fingering is reduced to a minimum.