Compositional Reservoir Simulation Research Articles

Non-iterative phase stability calculations for process simulation using discriminating functions

Phase stability calculations consume a significant part of a process or a compositional reservoir simulation CPU time as millions of two- or multi-phase equilibrium calculations on complex multicomponent mixtures need to be performed. The iterative nature of the solving methods involved in conjunction to the risk of false convergence render these computations as a hot research area. A new method is presented for generating discriminating functions of pressure, temperature and compositions which separate stable from unstable mixtures. These functions provide the same stability state predictions as the established minimum tangent plane distance since they exhibit exactly the same sign and zeroing points. Their simple explicit expressions allow for the rapid, non-iterative and robust evaluation of the stability state of the fluid under study. Being generated by using the fluid's Equation of State model they offer predictions which can be as accurate as the thermodynamic model itself. A set of examples demonstrates the accuracy of the proposed method as well as its very significant advantages with respect to computational speed.

K-value program for crude oil components at high pressures based on PVT laboratory data and genetic programming

Equilibrium ratios play a fundamental role in understanding the phase behavior of hydrocarbon mixtures. They are important in predicting compositional changes under varying temperatures and pressures in the reservoirs, surface separators, and production and transportation facilities. In particular, they are critical for reliable and successful compositional reservoir simulation. Several techniques are available in the literature to estimate the K-values. This paper presents a new model for predicting K values with genetic programming (GP). The new model is applied to multicomponent mixtures. In this paper, 732 high-pressure K-values obtained from PVT analysis of 17 crude oil and gas samples from a number of petroleum reservoirs in Arabian Gulf are used. Constant Volume Depletion (CVD) and Differential Liberation (DL) were conducted for these samples. Material balance techniques were used to extract the K-values of crude oil and gas components from the constant volume depletion and differential liberation tests for the oil and gas samples, respectively. These K-values were then used to build the model using the Discipulus software, a commercial Genetic Programming system, and the results of K-values were compared with the values obtained from published correlations. Comparisons of results show that the currently published correlations give poor estimates of K-values for all components, while the proposed new model improved significantly the average absolute deviation error for all components. The average absolute error between experimental and predicted K-values for the new model was 4.355% compared to 20.5% for the Almehaideb correlation, 76.1% for the Whitson and Torp correlation, 84.27% for the Wilson correlation, and 105.8 for the McWilliams correlation.

Compositional Streamline Simulation: A Parallel Implementation

Compositional reservoir simulators are needed to model oil recovery from petroleum reservoirs by miscible gas injection. This article describes the development and application of a parallel version of a compositional streamline simulator. A compositional streamline module is developed and integrated with an existing finite-difference simulator. Finite-difference calculations including pressure solution are performed on a single processor. The movement of fluids (which includes streamline tracing, mappings, flux calculations, and one-dimensional solver) is done along streamlines in the streamline module. The streamline module is parallelized by distributing streamlines among different processors because computations along any streamline are independent of other streamlines and no communication is required. Flux calculation along streamlines is computationally expensive primarily due to flash calculations that are performed to distribute components among the hydrocarbon phases. Simultaneous solution of this time-consuming step results in reduction of total CPU time. Communication (gathering) across the streamlines or processors is achieved by using message passing interface (MPI). Test runs are conducted for different examples to investigate the performance of the parallel streamline simulator. Results indicate that significant reduction in CPU time can be obtained by distributing streamlines on different processors.

Mechanisms for High Displacement Efficiency of Low-Temperature CO2 Floods

Summary CO2 floods at temperatures typically below 120°F can involve complex phase behavior, where a third CO2-rich liquid (L2) phase coexists with the oleic (L1) and gaseous (V) phases. Results of slimtube measurements in the literature show that an oil displacement by CO2 can achieve high displacement efficiency of more than 90% when three hydrocarbon phases coexist during the displacement. However, the mechanism for the high-displacement efficiency is uncertain because the complex interaction of phase behavior with flow during the displacement is not fully understood. In this paper, we present the first detailed study of three-phase behavior predictions and displacement efficiency for low-temperature CO2 floods. Four-component EOS models are initially used to investigate systematically the effects of pressure, temperature, and oil properties on development of three-phase regions and displacement efficiency. Multicomponent oil displacements by CO2 are then considered. We use a compositional reservoir simulator capable of robust three-phase equilibrium calculations. Results show that high displacement efficiency of low-temperature CO2 floods is a consequence of both condensing and vaporizing behavior. The L2 phase serves as a buffer between the immiscible V and L1 phases within the three-phase region. Components in the L1 phase first transfer efficiently to the L2 phase near a lower critical endpoint (LCEP). These oil components then transfer to the V phase near an upper critical endpoint (UCEP) at the trailing edge of the three-phase region. The CEPs are defined where two of the three coexisting phases merge in the presence of the other immiscible phase. Unlike two-phase displacements, condensation and vaporization of intermediate components occur simultaneously within the three-phase region. The simultaneous condensing/vaporizing behavior involving the CEPs is also confirmed for simulations of several west Texas oil displacements. Quaternary fluid models can predict qualitatively the complex displacements because four is the minimum number of components to develop CEP behavior in composition space at a fixed temperature and pressure.

Analysis of Uncertainty Introduced by Scaleup of Reservoir Attributes and Flow Response in Heterogeneous Reservoirs

SummaryReservoir heterogeneities occur over a wide range of length scales, and their interaction with various transport mechanisms controls the performance of subsurface flow and transport processes. Modeling these processes at large scales requires proper scaleup of petrophysical properties that are autocorrelated or heterogeneously distributed in space, and analyzing their interaction with underlying transport mechanisms.A method is proposed to investigate and quantify the uncertainty in reservoir models introduced by scaleup. It is demonstrated that when the volume support of the measurement is smaller than the representative elementary volume (REV) scale of the attribute to be modeled, there is uncertainty in the conditioning data because of scaleup and that uncertainty has to be propagated to spatial models for the attribute. This important consideration is demonstrated for mapping total porosity for a carbonate reservoir in the Gulf of Mexico. The results demonstrate that in most cases, the uncertainty distributions obtained by accounting for the scaleup procedure successfully characterize the variability in the actual core and log data observed along new wells. Conventional reservoir models considering the well data as "hard" conditioning data fail to predict the "true" values.Following this discussion on scaling of reservoir attributes, a conceptual understanding of the scaling characteristics of flow responses such as recovery factor (RF) is provided, in terms of the mean and variance of RF at different length scales. Finally, a new technique is presented to systematically quantify the scaling characteristics of transport processes by accounting for subscale heterogeneities and their interaction with various transport mechanisms based on the volume averaging approach. The objective is to provide a tool for understanding the scaling relationships for RF using detailed fine-scale compositional reservoir simulations over a subdomain of the reservoir.

Investigation into the capability of a modern decline curve analysis for gas condensate reservoirs

Techniques of production data analysis for single-phase oil and gas reservoirs have advanced significantly over the past few years. These techniques range from traditional (Arps and Fetkovich) to modern (for the variation of operating conditions at the wellbore). The application of these techniques for analysis of the production data of a gas condensate reservoir may not yield reliable answers due to the fact that the flow of fluid in gas condensate reservoirs is not single-phase. This paper presents the treatment of a modern method of production data analysis (single-phase flow) to analyze the production data of a gas condensate reservoir (two-phase flow). For this purpose, a single-phase production model is presented. Using a compositional reservoir simulator, long-term production data is generated over a wide range of gas condensate reservoir parameters. Next, a comparison is made between the simulator results (gas condensate) and the corresponding single-phase gas reservoir, using a modern production analysis method. The error for each case is analyzed, and a correlation for treatment of the single-phase analysis method is developed. Our results show that the methodology developed here can be successfully applied for analysis of the production data of a gas condensate reservoir.

Numerical modeling CO 2 injection in a fractured chalk experiment

This paper presents a numerical modeling study of CO 2 injection in a chalk core based on experimental data, as reported by Karimaie (2007). The experiment consisted of a vertically-oriented 19.6 cm long chalk outcrop core initially saturated with reservoir synthetic oil consisting of C 1 and n-C 7 at a temperature of 85 °C and pressure of 220 bar. After saturating the core with the oil mixture by displacement, a small “fracture” volume surrounding the core was created by heating the solid Wood's metal that originally filled the volume between the core and core holder. Gas injection was conducted initially using an equilibrium C 1–n-C 7 gas at 220 bar. This gas should have had no recovery by thermodynamic mass transfer, only from immiscible Darcy-controlled displacement driven by pressure gradients and gravity-capillary forces. Once oil production ceased in this first displacement, a second period with pure CO 2 gas injection followed. Our numerical modeling was conducted with a compositional reservoir simulator. The 2-dimensional r-z model used fine grids for the core matrix and the surrounding fracture. Automated history matching was used to match the experimental data (surface volumetric oil production profile). The match to reported production data gave a high degree of confidence in the model. Oil recovery improved significantly with CO 2 injection. Our numerical model study indicates that the recovery mechanism in the Karimaie experiment was dominated by Darcy displacement because of a low conductivity in the surrounding fracture, with little impact of capillary–gravity displacement. Another observation made in our study was the strong influence of surface separator temperature on surface oil volumetric production. Finally, gas-injection rate changes had a significant impact on recovery performance for CO 2 injection. Gravity–capillary recovery mechanism was of minor importance in the Karimaie experiments.

Modeling the effects of completion techniques and formation heterogeneity on CO2 sequestration in shallow and deep saline aquifers

This work studied the effect of completion techniques and reservoir heterogeneity on CO2 storage and injectivity in saline aquifers using a compositional reservoir simulator, CMG-GEM. Two reservoir models were built based on the published data to represent a deep saline aquifer and a shallow aquifer. The effect of various completion conditions on CO2 storage was then discussed, including partial perforation of the reservoir net pay (partial completion), well geometry, orientation, location, and length. The heterogeneity effect was addressed by considering three parameters: mean permeability, the vertical to horizontal permeability ratio, and permeability variation. Sensitivity analysis was carried out using iSIGHT software (design of experiments) to determine the dominant factors affecting CO2 storage capacity and injectivity. Simulation results show that the most favorable option is the perforation of all layers with horizontal wells 250–300 m long set in the upper layers. Mean permeability has the most effect on CO2 storage capacity and injectivity; kv/kh affects CO2 injectivity storage capacity more than permeability variation, Vk. More CO2 can be stored in the heterogeneous reservoirs with low mean permeability; however, high injectivity can be achieved in the uniform reservoirs with high mean permeability.

Analytical Correlations for Risk Parameters Involved in CO2 Storage

Abstract Large deep saline aquifers are present in different sedimentary basins throughout the world. The storage potential in these reservoirs is estimated at several thousands Gt CO 2 . The selection among the large number of prospective saline aquifers for CO 2 sequestration can be expedited with analytical correlations which can be used in place of a full field reservoir modeling and simulation study for each and every saline reservoir. The effectiveness of any CO 2 sequestration operation depends on pore volume and the sequestration efficiency of the saline reservoir. Sequestration efficiency is defined here as the maximum storage with minimum risk of leakage to the overlying reservoirs and to the surface. This can be categorized using three variables: time the plume takes to reach the top seal of the storage formation, maximum lateral distance the plume travels and the percentage of mobile CO 2 present at any time. A database has been created by performing a large number of compositional reservoir simulation studies for different elementary reservoir parameters. A single set of relative permeability curves is used in all simulation cases to maintain the consistency of the simulation parameters. A constant pressure far-field boundary is enforced by putting a number of producers at the boundary of the reservoir producing at constant bottom hole flowing pressure. This database is used to formulate different correlations that relate the sequestration efficiency to reservoir properties and operating conditions. The various elementary reservoir parameters are grouped into a dimensionless ratio of gravity forces and viscous forces. This ”gravity number” can be calculated for any saline reservoir without performing any simulation study, which makes it handy to use in different analytical models with various risk parameters. We improve the correlation for time to hit top seal proposed by Kumar and develop correlations for other two risk parameters by assuming radial grid system in place of Cartesian grid system. We find that normalizing all risk parameters with their respective characteristic values yields reasonable correlations with different variants of dimensionless gravity number. The characteristic values are determined with a characteristic flow speed equal to its value at the sand face. All correlations confirm the physics behind plume movement in a reservoir. For low gravity number displacement the plume travels preferentially in lateral direction due to high viscous forces and contacts more rock and brine volume, resulting in more trapping and less risk. On the other hand a high gravity number allows the plume to move faster in vertical direction due to strong gravity forces. This causes less interaction time and volume of resident brine and rock and results in less trapping of CO 2 . These analytical correlations are useful in characterizing a saline reservoir in terms of its sequestration efficiency without any reservoir simulation study, which in turn reduces the cost and time for commissioning a geological site for CO 2 sequestration.

Improved Delumping of Compositional Simulation Results

A recently developed method for pseudo-component delumping is tested for delumping the results of compositional reservoir simulation. The procedure, based on the reduction concept, is analytical and consistent and it accurately takes into account non-zero binary interaction parameters in cubic equations of state. The delumping method was implemented in a postprocessor to the commercial Eclipse reservoir simulator and successfully tested on several cases: oil and gas condensate reservoirs for depletion, lean gas re-injection, and carbon dioxide injection. The analytical delumping method based on reduction gives systematically better results than the regression-based delumping method used previously.

Analysis of the Storage Capacity for CO2 Sequestration of a Depleted Gas Condensate Reservoir and a Saline Aquifer

Summary Among the three types of geological CO2 sequestration (mature oil and gas fields, unminable coalbeds and deep saline formations), depleted gas condensate reservoirs are particularly interesting. First, because of the high-compressibility of gas, these reservoirs have larger storage capacity than oil reservoirs or aquifers. Second, the condensate that has dropped out from the gas phase during natural depletion will re-vaporize because of re-pressurization of the reservoir and by miscibility with the injected CO2. This condensate can be recovered from producing wells and leaves more pore volume for available storage of CO2. The objective of this study is to investigate the CO2 storage capacity in different formation types, for different levels of CO2 purity and different injection schedules. To this aim, we analyzed the injection of a CO2-based stream into a depleted gas condensate reservoir and into a saline aquifer using a compositional reservoir simulation model. The dynamics of the reservoir impose a minimum period of injection that is required in order for the storage scheme to benefit from 100% of the reservoir storage capacity. Hence, over and above a certain CO2 injection rate, it becomes meaningless to invest in bigger compressors to increase this rate to reduce the time of injection. When the CO2 stream contains impurities, such as N2 or methane, the storage capacity of the reservoir decreases proportionally to the impure stream's compressibility factor and its concentration of impurities. This finding suggests that an economic optimum between the costs of separation, compression and injection can be determined. Finally, the mass of CO2 sequestrated per pore volume in the equivalent aquifer model is approximately 13 times lower that of the depleted gas condensate reservoir model. This confirms that, because of their low overall compressibility, aquifers offer a far lower ratio of CO2 stored per pore volume than depleted gas condensate reservoirs. However, aquifers tend to have a far larger extent, which often compensates somewhat for this lower ratio and therefore provides storage for significant volumes of CO2.

A Fully Coupled Three-Phase Model for Capillary Pressure and Relative Permeability for Implicit Compositional Reservoir Simulation

Summary A coupled formulation for three-phase capillary pressure and relative permeability for implicit compositional reservoir simulation is presented. The formulation incorporates primary, secondary, and tertiary saturation functions. Hysteresis and miscibility are applied simultaneously to both capillary pressure and relative permeability. Two alternative three-phase capillary pressure formulations are presented: the first as described by Hustad (2002) and the second that incorporates six representative two-phase capillary pressures in a saturation-weighting scheme. Consistency is ensured for all three two-phase boundary conditions through the application of two-phase data and normalized saturations. Simulation examples of water-alternating-gas (WAG) injection are presented for water-wet and mixed-wet saturation functions. 1D homogeneous and 2D and 3D heterogeneous examples are employed to demonstrate some model features and performance.

Three-phase free-water flash calculations using a new Modified Rachford–Rice equation

A novel Modified Rachford–Rice equation is developed for three-phase equilibrium calculations in hydrocarbon–water systems, based on the free-water assumption, i.e., the water-rich liquid phase consists of pure water only. In the inner loop of the flash algorithm, the three-phase problem (consisting in a system of two non-linear equations) is replaced by a pseudo-two-phase problem (consisting in a non-linear equation). Unlike previous formulations, the new Modified Rachford–Rice function is guaranteed to monotonically decrease between two adjacent asymptotes. The negative flash concept is used, and a search window is proposed for the vapor fraction. The new free-water flash method proved to be robust, and excellent agreement between full three-phase flash and pseudo-two-phase free-water flash was obtained for various test problems. The proposed method is very useful in compositional reservoir simulation of certain oil recovery methods and in process simulation.

Phase-Behavior Study of Hydrocarbon/Water/Methanol Mixtures at Reservoir Conditions

Summary This paper presents a study of gas/condensate hydrocarbon mixtures and the effect of water, methanol, and isopropanol on their phase behavior. Only sparse data are available on the phase behavior of hydrocarbon/water/methanol mixtures at the high temperatures typical of these reservoirs. Such data are needed for compositional reservoir simulations of well treatments to optimize the performance of solvent treatments of blocked wells. Constant-composition expansion (CCE) experiments were performed to measure the phase behavior of hydrocarbon/water/methanol mixtures up to 300°F. The effects of temperature, pressure, and water and methanol concentration on the phase behavior were measured. The Peng-Robinson equation of state (EOS) was used to model hydrocarbon/water/methanol mixtures. The binary interaction parameters were tuned to fit the data and were found to show a linear variation with temperature. The binary interaction parameters and temperature-dependent volume-shift parameters are the key parameters to model these complex polar mixtures. Both the classical van der Waals and the Huron-Vidal (Huron and Vidal 1979) mixing rules were used and were found to give good agreement with the data. Phase-behavior experiments performed on hydrocarbon/water/isopropanol mixtures showed that isopropanol decreases the aqueous-phase volume fraction and increases the liquid-hydrocarbon-phase volume fraction compared with the analogous hydrocarbon/water/methanol mixtures. These data are needed to predict the conditions under which methanol/isopropanol treatments can be applied successfully in gas wells to remove water and condensate blockage.

An element-based finite-volume method approach for heterogeneous and anisotropic compositional reservoir simulation

An element-based finite-volume approach in conjunction with unstructured grids for heterogeneous and anisotropic compositional simulation is presented. This approach adds flexibility to map complex features of the reservoir such as irregular boundaries, discrete fractures, faults, inclined and distorted wells. The mesh, for two dimensional domains, can be built of triangles, quadrilaterals or a mix of these elements. According to the number of vertex, each element is divided into sub-elements and then mass balance equations for each component are integrated along each interface of these sub-elements. The finite-volume conservation equations are assembled from the contribution of all the elements that share a vertex creating a cell vertex approach. The results for several compositional reservoir simulation case studies are presented to demonstrate the application of the method.

Gas-Condensate Pseudopressure in Layered Reservoirs

Summary This paper presents verification of the Fevang and Whitson (1996) gas-condensate pseudopressure method for layered reservoirs. Layers may be characterized by widely varying permeability and composition, and they may be communicating or noncommunicating. The pseudopressure method is used in well calculations for coarse-grid models with relatively large areal grid dimensions (>50 m), capturing near-well condensate blockage without local grid refinement, thereby reducing run time and model size. The paper presents examples from several field studies and from two synthetic systems using a commercial reservoir simulator. The field studies include rich- and lean-condensate reservoirs. The study was conducted using a commercial compositional reservoir simulator. Three-dimensional multilayer, fine-grid (radial and Cartesian) models and equivalent coarse-grid models were used. Both depletion and gas-injection cases were simulated for a wide range of reservoir fluids. Reservoir performance of fine-grid models and coarse-grid models was compared using the gas-condensate pseudopressure method and showed comparable results in all cases studied, including relative permeabilities with capillary-number dependence and high-velocity (β) flow treatment. The coarse-grid model with pseudopressure is somewhat dependent on coarse-grid size, generally requiring Δx=Δy≈50-100 m for lean gas condensates and Δx=Δy≈100-200 m for rich gas condensates. The paper verifies for the first time that the gas-condensate pseudopressure method as proposed by Fevang and Whitson (1996) is valid and accurate for layered systems with significant heterogeneity (permeability variation), with and without crossflow, with and without capillary-number modification of relative permeabilities, and for widely ranging fluid compositions in each layer.

A Simulation of a Trap Mechanism for the Sequestration of CO2 into Gorae V Aquifer, Korea

This article presents the numerical modeling study to investigate the effect of CO2 sequestration in deep saline aquifer at Gorae V structure, Korea. This structure includes the Donghae-1 gas field, which is the only one producing in Korea. A simulation for 20 years of injection and 1,000 years of monitoring was conducted by using generalized equation-of-state model compositional reservoir simulator (GEM), which can simulate the flow of the CO2-water mixture to verify major trap mechanisms and sequestration characteristics in this system. By a number of simulations in reservoir conditions, the 3,000 ton/day of optimum injection rate was obtained within the limits of the rock fracturing pressure. As a result of simulation, since most of injected CO2 rises by a buoyancy and moves horizontally by the effect of cap rock, the radius of CO2 flowed out in the top layer is larger than bottom layer. Also, the change of dominant trap mechanism among structural, solubility, and residual trapping mechanism with time was examined. As residual gas saturation increases, the contact area between CO2 and formation water decreases. Thus, the quantity sequestrated by a solubility trap is reduced, and a greater amount of gas remains in the grid block. Also, gas saturation in some block was decreased below residual gas saturation due to the continuous dissolution and the formation water, accordingly, the formation water which its density was increased than surrounding blocks, sank to lower part of structure.

Integrated reservoir, petrophysical, and seismic simulation of CO2 storage in coal beds

In this paper, we present results of an integrated simulation study to assess the effectiveness of seismic imaging for monitoring [Formula: see text] sequestration. We considered two scenarios. In the first, injected [Formula: see text] remained confined within a shallow coal formation. In the second, the sequestered [Formula: see text] gas leaked through a semi-permeable shale layer to an overlying sand unit sealed above. In both scenarios, the [Formula: see text] injection process resulted in enhanced production of coal-bed methane. The reservoir and seismic simulations required the construction of 3D geologic and facies models, the estimations of seismic velocities based on rock physics correlations, and the development of geostatistical dual-porosity reservoir descriptions of the coal and overlying shale and sand units. We ran the 3D reservoir simulations with GEM 2008.10, an equation-of-state compositional reservoir simulator from Computer Modeling Group with the capability to model adsorption of injected [Formula: see text] in coal, desorption of [Formula: see text], and matrix shrinkage-swelling effects. The reservoir description was derived from a 3D geostatistical model of the Big George coal in the Powder River Basin. We used Batzle-Wang, Gassmann, and Mavko-Dvorkin-Mukerji relationships to incorporate the effects of mineral contents and changing reservoir properties on P-wave velocity. We built synthetic seismograms by simulating the propagation of acoustic waves through the 3D heterogeneous media, and used reverse time migration to create 3D seismic images corresponding to the state of the reservoir at the beginning and end of ten years of [Formula: see text] injection. The resulting seismic images clearly identified the regions of [Formula: see text] gas saturation, closely matching the gas-saturation profiles predicted by the reservoir simulator. Further research will be necessary to fine-tune an integrated reservoir simulation, rock physics modeling, and seismic imaging workflow to provide highly advanced imaging, monitoring, and verification capabilities for [Formula: see text] sequestration. This study is a first step toward this goal.

Simulating CO2 Sequestration in a Depleted Gas Reservoir

CO2 in atmosphere levels can be reduced by sequestering it directly to the underground. High amounts of CO2 can be safely stored in underground media for very long time periods. Storage in depleted gas reservoirs provides an option for sequestering CO2. CO2 sequestration in Kuzey Marmara field has been considered in this study as an alternative to the gas storage projects. The reservoir still contains producible natural gas. Four scenarios were prepared by considering this fact with variations in the regional field properties and implemented into a previously built simulation model. Reservoir porosity and permeability maps were prepared and merged with Kuzey Marmara production information to create an input file for a computer modeling group-full equation of state compositional reservoir simulator (CMG-GEM) simulator, and a three-dimensional model of the reservoir was created. After analyzing the results from the scenarios it is realized that CO2 injection can be applied to increase natural gas recovery of Kuzey Marmara field but sequestering high rate CO2 emissions is found to be inappropriate.

Compositional Space Parameterization: Theory and Application for Immiscible Displacements

Summary Thermodynamic equilibrium calculations in compositional flow simulators are used to find the partitioning of components among fluid phases, and they can be a time consuming kernel in a compositional flow simulation. We describe a tie-line-based compositional space parameterization (CSP) approach for dealing with immiscible gas-injection processes with large numbers of components. The multicomponent multiphase equilibrium problem is recast in terms of this parameterized compositional space, in which the solution path can be represented in a concise manner. This tie-line-based parameterization approach is used to speed up the phase behavior calculations of standard compositional simulation. Two schemes are employed. In the first method, the parameterization of the phase behavior is computed in a preprocessing step, and the results are stored in a table. During the course of a simulation, the flash calculation procedure is replaced by the solution of a multidimensional optimization problem in terms of the parameterized space. For processes where significant changes in pressure and temperature take place, this optimization procedure is combined with linear interpolation in tie-line space. In the second method, compositional space adaptive tabulation (CSAT) is used to accelerate the equation of state (EOS) computations associated with standard compositional reservoir simulation. The CSAT strategy takes advantage of the fact that, in gas injection processes, the solution path involves a limited number of tie-lines. The adaptively collected tie-lines are used to avoid redundant phase-stability checks in the course of a flow simulation. Specifically, we check if a given composition belongs to one of the tie-lines (or its extension) already in the table. If not, a new tie-line is computed and added to the table. The CSAT technique was implemented in a general-purpose research simulator (GPRS), which is designed for compositional flow simulation on unstructured grids. Using a variety of challenging models, we show that, for immiscible compositional processes, CSAT leads to significant speed up (at least a several-fold improvement) of the EOS calculations compared with standard techniques.