Dew Point Pressure Research Articles

Experimental and modeling study of CO2 - Improved gas recovery in gas condensate reservoir

Abstract This paper presents the effectiveness of the CO 2 injection process at different periods during gas-condensate reservoir development. Taking a real gas-condensate reservoir located in China's east region as an example, first, we conducted experiments of constant composition expansion (CCE), constant volume depletion (CVD), saturation pressure determination, and single flash. Next, a series of water/CO 2 flooding experiments were been investigated, including water flooding at present pressure 15 MPa, CO 2 flooding at 25.53 MPa, 15 MPa, which repents initial pressure and present pressure respectively. Finally, the core flooding numerical model was constructed using a generalized equation-of-state model reservoir simulator (GEM) to reveal miscible flooding mechanism and the seepage flow characteristics in the condensate gas reservoir with CO 2 injection. A desirable agreement achieved in experimental results and predicted pressure volume temperature (PVT) properties by the modified equation of state (EOS) in the CVD and CCE tests indicated that the proposed recombination method can successfully produce a fluid with the same phase behavior of initial reservoir fluid with an acceptable accuracy. The modeling results confirm the experimental results, and both methods indicate that significant productivity loss can occur in retrograde gas condensate reservoirs when the flowing bottom-hole pressure falls below dew point pressure. Moreover, the results show that CO 2 treatment can improve gas productivity by a factor of about 1.39 compared with the water flooding mode. These results may help reservoir engineers and specialists to restore the lost productivity of gas condensate.

An efficient approach for optimizing full field development plan using Monte-Carlo simulation coupled with Genetic Algorithm and new variable setting method for well placement applied to gas condensate field in Vietnam

This paper presents an efficient technique to optimize a gas condensate field development plan under economic uncertainties. Many studies have been conducted to optimize development plan but mostly limited to oil field under fixed economic environments and required huge number of simulation runs. It is proved that black oil model can be a reasonable alternative of compositional model to complete field development optimization within acceptable period when reservoir pressure is higher enough than dew point pressure. This study implements Monte-Carlo simulation to Genetic Algorithm to assess economic uncertainties while optimization procedure is being performed and to avoid duplicating whole optimization procedure by changing economic assumptions. An idea for setting optimization variables for well placement is also introduced to reduce required number of simulation runs. A real field application confirms that the technique can be applied to optimize a gas condensate field with contractual gas sales obligation, and the idea plays a key role to find the optimized solution with limited resources by reducing the number of simulation runs required during the optimization procedure. The proposed technique can be applied to optimize not only full field development plan but also reservoir management plan and it will be helpful to improve economics of all kinds of E&P projects under lots of uncertainties.

Evaluation of effective parameters on CO2 injection process in a gas condensate reservoir: A case study

ABSTRACTOne of the key problems in gas condensate reservoirs is condensate blockage phenomena or condensate banking that reduces the condensate recovery. This phenomenon occurs when by reservoir depletion the reservoir pressure declines below the dew point pressure. One of the most important and common methods to prevent condensate blockage is gas cycling. Nowadays, regarding the value of natural gas, the use of other gases such as CO2 as a suitable replacement has increased. The purpose of this study is to evaluate different parameters such as injection rate, injection pressure, and the number of wells in CO2 injection process, in order to determine optimum conditions for CO2 injection with the maximum condensate recovery and minimum economic cost. The two-parameter, Peng–Robinson equation of state (EOS) was used to match PVT experimental data. Then various scenarios of CO2 injection with different conditions have been studied, and optimum conditions for CO2 injection were compared with the natural depletion scenario. The results showed that the injection rate and pressure play important roles in determining the best condensate recovery.

Recovery enhancement at the later stage of supercritical condensate gas reservoir development via CO2 injection: A case study on Lian 4 fault block in the Fushan sag, Beibuwan Basin

Lian 4 fault block is located in the northwest of Fushan sag, Beibuwan Basin. It is a high-saturated condensate gas reservoir with rich condensate oil held by three faults. In order to seek an enhanced condensate oil recovery technology that is suitable for this condensate gas reservoir at its later development stage, it is necessary to analyze its reserve producing degree and remaining development potential after depletion production, depending on the supercritical fluid phase behavior and depletion production performance characteristics. The supercritical fluid theories and multiple reservoir engineering dynamic analysis methods were adopted comprehensively, such as dynamic reserves, production decline, liquid-carrying capacity of a production well, and remaining development potential analysis. It is shown that, at its early development stage, the condensate in Lian 4 fault block presented the features of supercritical fluid, and the reservoir pressure was lower than the dew point pressure, so retrograde condensate loss was significant. Owing to the retrograde condensate effect and the fast release of elastic energy, the reserve producing degree of depletion production is low in Lian 4 fault block, and 80% of condensate oil still remains in the reservoir. So, the remaining development potential is great. The supercritical condensate in Lian 4 fault block is of high density. Based on the optimization design by numerical simulation of compositional model, it is proposed to inject CO2 at the top and build up pressure by alternating production and injection, so that the secondary gas cap is formed while the gravity-stable miscible displacement is realized. In this way, the recovery factor of condensate reservoirs can be improved by means of the secondary development technology.

Robust Pediction of Double Retrograde Vaporization by Numerical Inversion of Functions

Double retrograde vaporization is a thermodynamic phenomenon that occurs in mixtures formed by a solute with low volatility when compared to the solvent. Specially in high pressures, when the mixture reaches a temperature which is higher than the critical temperature of the pure solvent, the phase equilibriumcan exhibit four different solutions (dew point pressures and liquid phase compositions), characterizing a very unique behavior. Because of the difficulty in predictingliquid molar fractions and pressure in which this phenomenon occurs, it makes the problem areal challenge for the supercritical fluid and oil industry. The occurrence of this physical phenomenon will be illustrated in a binary system formed by ethane + limonene. Under certain conditions, the problem can be modelled through a 2 × 2 system of nonlinear algebraic equations. This fact makes it possible to predictthe phenomenon of double retrograde vaporization by numerical inversion of functions from a subset of the plane to the plane. This method canobtain all the solutions of the problem in a robust and efficient way, besides offering a basis for conducting a qualitative analysis of the function behavior.

Optimization of huff-n-puff gas injection in a shale gas condensate reservoir

Condensate blockage is a serious problem in shale gas condensate reservoirs. As the pressure decreases lower than dew point pressure, condensate forms. This condensate reduces the relative permeability of gas and the productivity of shale gas condensate reservoirs.Huff-n-puff gas injection is an EOR method in which a well alternates between injection, soaking, and production. Based on the laboratory study conducted by Meng et al. (2015), huff-n-puff gas injection was proven as an effective method to enhance condensate recovery for Eagle Ford shale cores. In this paper, a numerical reservoir simulation study is conducted to optimize the application of huff-n-puff gas injection in an Eagle Ford shale gas condensate reservoir. During the injection and soaking process, the pressure of the reservoirs built up, the condensate was revaporized to gas, and then was produced during the production process. Different parameters were investigated including injection time, soaking time, production time, and cycle numbers.The results show that huff-n-puff gas injection is an effective method to enhance condensate recovery in the Eagle Ford shale gas condensate reservoir. It was found that the optimum injection time is the time during which the pressure of the main condensate region can be increased higher than dew point pressure. Also, shorter or even no soaking is more effective. The production time depends on the production decline rate. It is more profitable to start another cycle of huff-n-puff gas injection when the production rate is decreased to a low value.

Experimental and numerical study of huff-n-puff gas injection to re-vaporize liquid dropout in shale gas condensate reservoirs

The complex flow behavior of a gas condensate reservoir is caused by the compositional changes and the creation of condensate blockage around the wellbore. Once the pressure is lower than the dew point pressure, liquid dropout is formed in the reservoir. This liquid dropout reduces gas relative permeability. As a consequence, gas production is decreased and liquid dropout-condensate, a valuable resource, remains in the reservoir.In this paper, the re-vaporization mechanism of huff-n-puff gas injection is investigated from both experimental and numerical work. In huff-n-puff gas injection, when pressure is increased to be higher than the dew point pressure, part of the condensate can be re-vaporized and flows to the production well with gas during the puff process. Since there is only one well in the huff-n-puff process, the condensate region is near the well. When gas is injected into the reservoir, the pressure of the condensate region will be increased rapidly. Very limited research has been conducted on the re-vaporization of condensate, especially for shale gas condensate reservoir.Both experimental work and simulation study have confirmed the mechanism of condensate re-vaporization by huff-n-puff gas injection. The work from this paper indicates that huff-n-puff is an effective way to re-vaporize the condensate and enhance the condensate recovery.

GA-RBF model for prediction of dew point pressure in gas condensate reservoirs

This study presents the application of an intelligent algorithm in estimation of dew point pressure (DPP) of gas condensate systems. Radial Basis Function (RBF) network in conjunction with Genetic Algorithm (GA) as an optimization algorithm was utilized for this aim. The performance of the proposed GA-RBF model was investigated by statistical and graphical analysis of results. The analysis show that the implemented model is precise and robust in prediction of experimental DPP data. Furthermore, the GA-RBF model was compared with a literature intelligent approach (GEP model) as well as three well-known correlations. The comparison reveals that the GA-RBF model is superior to other model and correlations and successfully improves the predictions.

The Effect of Fluoropolymer on Wettability Alteration of Sandstone at Elevated Temperatures

AbstractGas condensate reservoirs are generally recovered using a pressure depletion drive. Gas can condensate into the liquid phase near the wellbore region when the reservoir pressure falls below the dew point pressure, which can kill gas deliverability. Wettability alteration is an effective means of overcoming this problem; core wettability can be altered from liquid‐wet to gas‐wet to alleviate the effect of condensate accumulation near the wellbore region. To establish the effect of fluoropolymer on wettability alteration in a gas‐condensate reservoir, a gas‐wetting alteration agent was synthesized by emulsion polymerization using different molar ratios of fluorine‐containing monomers and acrylic monomers. FTIR and SEM were performed to analyze the structure of the gas‐wetting agent. Contact angle measurements were used to assess surface alteration by the Owens two‐liquid method. The effects of alteration agent concentration, salt concentration, pH and temperature on gas‐wetting alteration were also evaluated. Results showed that the best molar ratio of fluoropolymer monomer to acrylic monomers was 1:2. The egg‐like structure of the fluoropolymer latex on the core surface mainly contributes to gas‐wetting alteration. The contact angles of brine and oil can be altered from 23° and 0° to 137° and 67° by 1 wt% FP‐2 treatment, respectively. The surface free energy of the core was reduced from 67.52 to 1.66 mN/m. Moreover, the treated cores remain gas‐wetting up to 100 g L−1 of salt solution, 120 °C and within the pH range of 5–7. This novel gas‐wetting alteration agent can be used to solve the problem of liquid blocking effects in gas condensate reservoirs and improve gas recovery significantly.

A new Peng-Robinson modification to enhance dew point estimations of natural gases

Equations of state (EOSs) are widely used in calculations such as those involving reservoir simulation, process simulation, gas processing and transportation of natural gas. Predicting the phase envelope, specifically the dew points of natural gas, is among the important roles of EOSs. In this study, a modification is proposed to improve the predictions of dew point properties by the Peng-Robinson (PR) EOS, where the attraction parameter has been modified by a new empirical-based coefficient which is a function of reduced pressure, reduced temperature and critical density. In order to validate the modification, results are presented for four major properties of dew points consisting of the cricondentherm, cricondenbar, dew point temperature and dew point pressure. Furthermore, the performances of the original PR, Soave-Redlich-Kwong (SRK), Schmidt-Wenzel (SW) and GERG-2008 EOSs have been compared to predict the above four properties with respect to the experimental data. Having similar qualitative trends for the four properties, the results show that the modification of this study gives better predictions of the dew point curves, followed by the GERG EOS, which was developed particularly for processed natural gases. The SRK and SW EOSs have comparatively similar results and the PR EOS has the largest deviations.

Characterisation of a microwave re-entrant cavity resonator for phase-equilibrium measurements and new dew-point data for a (0.25 argon + 0.75 carbon dioxide) mixture

An apparatus based on a microwave re-entrant cavity resonator, originally built for accurate measurements of the dielectric permittivity of natural gas mixtures, was refurbished and extensively characterised. This was done to enable the future investigation of phase equilibria and (p, ρ, T, x) behaviour of fluid mixtures utilizing the present experimental technique. Vacuum resonance frequencies and Q-factors of the resonator’s modes were modelled using both analytic and finite element methods, and found to compare well with experimental values. The finite element models helped to identify two whispering gallery-type modes not previously reported for such cavity geometries. The models also predict distributions of the electric and magnetic fields in the re-entrant cavity resonator useful for identifying regions in the cavity more sensitive to the presence of a liquid. Following the resonator’s characterisation, its ability to measure dew points was tested using a gravimetrically prepared (0.2501 argon+0.7499 carbon dioxide) mixture over the temperature range from (252 to 280)K at pressures from (2.8 to 6.9)MPa. The combined expanded uncertainty with a level of confidence of approximately 95% (k=2) in dew-point temperature and pressure ranged between (0.025 and 0.044)K and from (0.009 to 0.015)MPa, respectively. We compared the experimental dew-point pressures with the recently developed multi-parameter equation of state optimised for combustion gases (EOS-CG), showing relative deviations in the range of (0.044 to 0.479)%. In contrast, relative deviations of up to −4% from the GERG-2008 equation of state and two different implementations of the Peng-Robinson equation were observed, although these models are not optimised for dew point calculations of carbon dioxide rich mixtures.

Vapor-Phase (p, ρ, T, x) Behavior and Virial Coefficients for the Binary Mixture (0.05 Argon + 0.95 Carbon Dioxide) over the Temperature Range from (273.15 to 323.15) K with Pressures up to 9 MPa

Accurate density measurements on a binary (argon + carbon dioxide) mixture were carried out at temperatures T = (273.15, 283.15, 293.15, 308.15, and 323.15) K with pressures up to the dew-point pressure or 9.0 MPa, whichever was lower. A two-sinker magnetic suspension densimeter was utilized for the measurements. The composition of the gravimetrically prepared mixture was 0.94951 mole fraction carbon dioxide. Taking the measurement uncertainties in temperature, pressure, density, and composition into account, the relative combined expanded uncertainty (k = 2) in density was estimated to be less or equal 0.043% of the measured density value. Relative deviations of the new experimental data from the GERG-2008 equation of state (EOS) and from the EOS-CG (a recently developed multiparameter EOS optimized for combustion gases) were within 0.95% and 0.18%, respectively. Third-order virial equations were fitted to the new experimental data. The correlated molar masses at different isotherms agreed with the gravi...

Transient pressure test analysis of horizontal wells in gas condensate reservoirs: Evaluation of conventional multi-phase pseudo-pressure solutions

Transient pressure test analysis, as a tool to well and reservoir characterization, is not well developed in two-phase horizontal wells. As our best knowledge, potential of conventional multiphase pseudo-pressure solutions in horizontal well test analysis of gas condensate reservoirs below dew-point pressure has not been demonstrated yet. The most challenge is that flow regime around horizontal wells is not constant. Also, high velocity effects near wellbore are the other main conflict which need more investigation.The objective of this paper is to express encountered challenges in transient pressure test analysis of horizontal wells in gas condensate reservoirs below saturation pressure. For this purpose, based on simulated models, potential of the conventional multiphase pseudo-pressure solutions to interpret pressure behavior of these wells is examined. Also, their potential to estimate well and reservoir properties is investigated. After that, the reason for inability of these solutions in well test analysis of horizontal wells is explored. Furthermore, the effects of near wellbore phenomena on two-phase horizontal gas wells are studied.The results show that, during early radial flow, once bottom-hole pressure falls below dew-point, pressure data shows a composite behavior; however, two phase pseudo-pressure responses calculated by both steady-state and 3-zone solutions, can accurately correct the effect of liquid saturation. In the result, reservoir permeability is estimated with a good accuracy. The study also expressed that, during other flow regimes, deviation from single phase flow due to condensate accumulation cannot be corrected using conventional solutions of two-phase pseudo-pressure function. The reason is that fluid composition is not constant during any of the flow regimes except radial flow. Though, constant fluid composition is the basic assumption for the conventional solutions. Moreover, the result shows that non-Darcy effect in two-phase flow is less than single-phase. Also, positive coupling effect around horizontal wells is not as much significant as vertical wells.

Examination of unconventional phenomena in naturally fractured liquid-rich gas reservoirs: single-block compositional model

During the depletion of liquid-rich gas reservoirs, the gas condenses as the pressure inside the reservoir reduces below the hydrocarbon dew-point pressure, which introduces retrograde condensate. In such conditions, the productivity experiences a reduction in recovery due to the appearance of condensate near the production channels. This work is aimed to provide insight on productivity characteristics of a liquid-rich gas system in unconventional environments and extend the scrutiny on the propagation of condensate while activating capillary forces and diffusion. The impact of capillary pressure on phase behavior was explored using an in-house generated coupled phase behavior model with a capillary pressure equation. The influence of capillary pressure was examined against different sets of composition combinations in different reservoir settings. Capillary force extents were highly dependent on composition combinations and pore throat radiuses. Mixtures with higher volatile concentrations showed the highest capillary forces. The enhancement in condensate propagation, resistance to gas flow, and impact on recovery were explored at 10- and 20-nm pore throat sizes. The investigation suggested that interfacial tensions implied greater influence on the flow behavior in oil-dominated systems than in gas-dominated conditions. Evaluating the flow performance of unconventional phenomena in liquid-rich gas reservoirs was extended to include diffusion while activating capillary forces. The results showed higher domination of diffusion on reservoir performance, which provided additional fluid recovery. Subsequently, the enhanced withdrawal of fluid dismissed the impact of capillary forces on gas flow and the impact of condensate blockage.

Dew point pressure model for gas condensate reservoirs based on multi-gene genetic programming approach

One of the most critical parameters in characterization of gas condensate reservoirs is dew point pressure (DPP), and its accurate determination is a challenging task in development and management of these reservoirs. Experimental measurement of DPP is a costly and time consuming method. Therefore, searching for a quick, reliable, inexpensive, and robust algorithm for determination of DPP is of great importance. In this paper, first, a new approach based on multi-gene genetic programming (MGGP) to determine DPP of gas condensate reservoirs is presented. Then, a correlation for DPP calculation using MGGP has been developed for gas condensate reservoirs. Finally, the efficiency of the proposed DPP model has been validated by comparing its predictions with the results of other conventional models. It is found that the correlation developed in this work is capable of predicting more accurate values of DPP, with the lowest average relative and absolute errors with respect to the experimental results, and also higher correlation coefficient among the results of all the evaluated DPP correlations. Therefore, it is suggested that the proposed model can be applied effectively for DPP prediction for a wide range of gas properties and reservoir temperatures.

Robust correlation to predict dew point pressure of gas condensate reservoirs

Abstract When the bottom-hole flowing pressure in a gas condensate reservoir drops below the dew point pressure, liquid starts to build up around the well bore resulting in gas productivity decline. For this reason it is important to be able to accurately either measure or estimate the dew point pressure. The condensate formed in the reservoir will not flow until its saturation reaches the critical saturation and in many cases it might not be entirely recovered. It order to maximize gas production and condensate recovery, the reservoir pressure must be maintained close to the dew point pressure. Several attempts have been made to predict the dew point pressure in case the gas sample becomes unavailable or measured value is unreliable. Unfortunately, most of these attempts have minor success rates and are based on limited data. In this paper we present a robust, cheap, and easy model for predicting the dew point pressure for gas condensate reservoirs. The new model is an intelligent based model called “Gene Expression Programming” that is carried out to generate a precise and accurate correlation to estimate the dew point pressure in condensate gas reservoirs. The new model has been trained and tested using a large data bank collected for the literature. Precision of the suggested correlation has been compared to published correlations. The validity of this model has also been compared to experimental data and other published correlations.

Mitigation of the Effects of Condensate Banking: A Critical Review

Summary With production from gas/condensate reservoirs, the flowing bottomhole pressure of the production well decreases. When the flowing bottomhole pressure decreases below the dewpoint, condensate accumulates near the wellbore region and forms a condensate bank. This results in a loss of productivity of both gas and condensate, which becomes more serious in intermediate- and low-permeability gas/condensate reservoirs, where the condensate bank reduces both the gas permeability and the well productivity. Several techniques have been used to mitigate this problem. These methods include: Use of solvents and wettability-alteration chemicals to reduce the impact of condensate blockage Gas cycling and injection of nitrogen and supercritical carbon dioxide as pressure-maintenance methods Drilling horizontal wells, hydraulic fracturing, and acidizing to improve the well productivity Gas cycling aims to keep the reservoir pressure greater than the dewpoint pressure to reduce the condensation phenomena. The limited volumes of gas that can be recycled in the reservoir can hinder the application of this method. For an ideal gas-cycling process, the volume of the gas injected into the reservoir will be larger than the total gas that can be produced from such a reservoir. Other approaches are the drilling of horizontal wells and hydraulic fracturing, during which the pressure drop around the wellbore region is lowered to allow for a longer production time, with only single-phase gas flow to the wellbore. These approaches are costly because they require drilling rigs. Another technique is the use of solvents, which shows good treatment outcomes, but the durability is a questionable issue in these treatments. Moreover, wettability alteration needs to be approached very carefully so as not to cause permanent damage to the reservoir. The use of fluorinated polymers and surfactants dissolved in alcohol-based solvents for wettability-alteration treatments was reported in many studies. Each method has its own advantages and disadvantages, and can be applied under certain conditions. This paper presents all of these methods, along with their advantages and disadvantages and description of some of their field applications and case studies.

Effect of Capillary Condensation on Gas Transport in Shale: A Pore-Scale Model Study

SummaryThe condensation of the gas inside nanopores at pressures lower than the dewpoint pressure, or capillary condensation, is an important physical phenomenon affecting the gas flow/transport process in shale. This work investigates the underlying transport mechanism and governing factors for the gas transport at a pore scale associated with capillary condensation. We numerically simulate and compare the gas-transport process within pores for two cases, with and without capillary condensation, while Knudsen diffusion, wall slippage, and phase transition are included in the numerical model. In each case, the simulations are performed for two pore geometries corresponding to a single pore and two parallel-connected pores. The main objective is to determine whether capillary condensation blocks or enhances gas transport during production. The results show that the presence of the liquid phase in the pore throat initially enhances the gas flow rate to the outlet of the pore, but significantly reduces it later. This blockage depends on pore geometry and the properties of the oil and gas phases. The relatively low mobility of the condensed liquid in the pore throat is the main factor that reduces the mass transport along the pore. The reduction of overall mass transport in a single pore is more significant than that for the parallel pore geometry. Implications of this work for predicting large-scale gas transport in shale are also discussed.

Modelling the phase equilibria of multicomponent mixtures containing CO2, alkanes, water, and/or alcohols using the quadrupolar CPA equation of state

ABSTRACTIn this work, a quadrupolar cubic plus association (qCPA) equation of state is evaluated for its ability to predict the phase equilibria of multicomponent mixtures containing CO2 and alkanes, alcohols, and/or water. A single binary interaction parameter is employed in qCPA for all binary combinations. All parameters are based solely on pure fluid or binary mixture data and multicomponent data are used only to evaluate the predictions. The performance of qCPA is, for all mixtures, compared to CPA where CO2 is considered to be either non-associating (inert), solvating or self-associating. In the latter two approaches, an additional adjustable parameter is employed for binary pairs of CO2 and an associating compound. The results show that the predictions with qCPA are very similar to the best performing CPA approaches, even though the model uses fewer adjustable binary parameters. The predictions with qCPA and the best CPA approaches are typically satisfactory and predict the general behaviour of the systems. As expected, qCPA and CPA with solvation or association typically performs better than inert CPA for two- and three phase vapour–liquid and vapour–liquid–liquid equilibria. However, inert CPA yields the best results of all the models for the prediction of dew point pressures.

Extrapolation of black- and volatile-oil fluid properties with application to immiscible/miscible gas injection

Black-oil fluid properties are determined by lab measurements or can be calculated through flash calculations of the reservoir fluid. Allowing for variable bubble-point pressures in black- or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. Reservoir simulation accuracy, however, may be affected by discontinuities in the input data and poor predictions of extrapolated fluid properties. Common practice is to add surface gas to the original oil in the lab and increase the pressure to reach a new bubble-point. Another approach is to use linear extrapolation of oil and gas K-values with pressure on a log-log plot, where K-values are equal to 1.0 at a pseudo-critical or convergence pressure. The latter approach results in discontinuities in the phase behavior.We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached at the top of the pseudocomponent pressure-composition diagram. Unlike other methods commonly used or recently proposed, the approach provides a smooth and continuous pressure-composition curve to the critical point. The model further allows for reinjection of produced gas, methane, or CO2 to increase oil recovery for both volatile and black oils. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure alters the saturation pressures by decreasing the bubble-point pressure or increasing the dew-point pressure. Bubble-point pressure in the new model is a function of both capillary pressure (effective pore radius) and gas content. The phase behavior is illustrated using ternary diagrams for up to four components (water, oil, gas, and CO2 or CH4) and three phases (aqueous, oleic, gaseous) to allow for miscible and immiscible injection of various gases. The new phase behavior could be easily incorporated in a compositionally-extended black- or volatile-oil simulator. The approach could also be used to model gas condensate reservoirs with or without gas injection and capillary pressure. Finally, 1-D slim-tube simulations are made with the extrapolated black oil fluid properties to estimate minimum miscibility pressure (MMP) to demonstrate the applicability of the approach. Shocks occur in the 1-D displacement consistent with a compositional simulator.