Acid Gas Mixtures Research Articles

Mechanistic analysis of acid gas storage and oil recovery in naturally fractured reservoirs using single matrix block approach

AbstractThe objective of this study is to assess the storage of acid gas, containing CO2 and H2S, in a depleted naturally fractured reservoir (NFR) using single matrix block (SMB) approach. The acid gas dissolution in oil is considered by Peng‐Robinson equation of state and compositional simulation. The PHREEQC package is used to determine acid gas solubility in formation brine. Three types of acid gases with different compositions are used for this study and their swelling behavior and miscibility in relation to the reservoir oil are analyzed. An SMB model, with a matrix block surrounded by fractures, is constructed, and validated for simulation of a real experiment. The simulation is conducted for synthetic and real reservoir fluids when the oil is in its residual saturation. A sensitivity analysis is performed to study the effects of key parameters, such as acid gas composition, reservoir pressure, permeability, porosity and matrix height on the storage capacity and oil recovery factor. The matrix has a volume of 27 m3 and about half of acid gas storage is achieved in the first 5 years while the simulations are run for 30 years. The results show that up to 90% of remained oil is recoverable, and more than 0.67 kmol of acid gas per cubic meter of matrix is stored whether matrix contains a real oil or a synthetic one. Higher storage is achieved for higher matrix porosities and heights and large H2S proportion in acid gas. In all cases about 10% of acid gas is trapped in water and the remaining 90% is dissolved in oil. The mineral trapping was more active in CO2‐rich acid gases. While about 10 kg of the matrix rock was dissolved in the acidic brine when the acid gas contained H2S, the amount of the dissolved minerals in acidic brine resulted from the injection of CO2‐rich acid gas was more than 16 kg. Finally, this study gives a comparative analysis of the storage performance of acid gas mixture and pure CO2. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Improving the prediction of elemental sulfur solubility in sour gas mixtures by modifying cubic equations of state

So far, several correlations have been developed to forecast the solubility of sulfur in various mixtures of acid gases with different concentrations of hydrogen sulfide. These correlations are correlative methods requiring experimental sulfur solubility data to tune their model parameters. Besides, correlative methods have many restrictions and are useable only for a limited range of operating conditions. Another approach for predicting sulfur solubility is applying equations of state. The predictive ability of equations of state has made them a powerful tool to more accurately perform the equilibrium phase calculations of acid gas mixtures in a vaster operating range. The major problem of the equations of state is the inaccurate characterization of their parameters for elemental sulfur due to its chemical complexity. In this study, the performance of three cubic equations of state is evaluated for forecasting the solubility of elemental sulfur in different acid gas mixtures. The main idea which is supposed to be put forward for rectifying defects of cubic equations of state is to model the trend of errors propagated in predicting the solubility of sulfur. Indeed, the effect of sulfur chemical reactions is ignored, and a generalized correction function is developed to compensate for deviations arising from the simplification assumptions. Subsequently, the results predicted by modified equations of state are compared to experimental sulfur solubility data and previously existing methods. Finally, a case study is performed on a sour gas reservoir sample to predict precipitation P-T curve and to calculate sulfur solubility changes with the pressure and temperature reduction throughout the gas well. Predicted results revealed the proposed correction function could significantly decrease the solubility calculations obtained from the modified equations of state under 5.6%, which is a good achievement compared to their original versions.

Effect of higher H2S concentration over CO2 in acid gas mixtures during geosequestration

Decarbonisation of most industrial processes is imperative to achieve climate neutrality. In oil and gas, carbon dioxide (CO2) and natural gas are being discovered together with increasingly higher quantities of hydrogen sulphide (H2S). The negative effects of acid gases (predominantly CO2 and H2S) in that industry mean they have to be separated before both natural gas and petroleum fuels can be classified as safe for transportation and usage. The separated acid gas, usually composed of a higher CO2 volume is stored and utilised in enhanced oil recovery (EOR) or geologically stored (geosequestered) in formations. There are increasingly instances in which higher volume of H2S acid gas mixtures are being discovered and explored. In this work, the effects of a higher mole percentage H2S in an acid gas mixture is investigated using molecular dynamics simulations. The analysis found that it was easier for higher CO2 acid mixtures to reach pressure convergence comparatively. It has also been discovered that higher H2S acid gas mixtures had lower interfacial tension, which makes them more hydrophilic and more miscible with the formation water. The higher H2S acid gas content mixtures also have wider water coverage widths and greater interfacial interactivity between the injected and formation fluids. From the density profiles, H2S gas in the higher H2S acid gas mixture is found to have more influence on the higher H2S acid gas/water injection/sequestration process compared to the effect of CO2 on the higher CO2 acid gas mixture/water. While H2S is slightly more polar than the nonpolar CO2, the carbon of CO2’s ability to form strong dipole–dipole interactions with the oxygen of water increases the CO2's polarity, and this is reflected in the assertion of the primacy of the {text{O}}_{{{text{H}}_{{2}} {text{O}}}} cdots {text{C}}_{{{text{CO}}_{{2}} }} interaction over all other pairs from the radial distribution function in the water/acid gas mixture during geosequestration. This demonstrates also that a reduction in interfacial tension is possible even for hydrophobic phases.

Transport properties of mixtures of acid gases with aqueous monoethanolamine solutions: A molecular dynamics study

We investigated the effect of temperature and monoethanolamine (MEA) concentration on the self-diffusivity of acid gases, CO2 , and H2S in aqueous MEA solutions. For this purpose, we computed densities of pure MEA and 30 wt% MEA/water solutions while scaling the LJ energy (ϵ) parameter and point charges of MEA. Results show that with a scaling factor of 0.80 applied to the point charges of MEA, computed densities agree well with the experimental ones from literature. This was tested by computing viscosities and the self-diffusivity of pure MEA and 30 wt% MEA/water solutions and comparing these with experiments. We showed that the scaling factor of 0.80 also works well for predicting transport properties of MEA/water solutions. Finally, we computed self-diffusivities of infinitely diluted CO2 and H2S for temperatures ranging from 293–353 K and MEA concentrations of 10–50 wt%. Our results show that the self-diffusivity of both acid gases depends significantly on the temperature and MEA concentration in the solution. The results of this study will contribute to the development of more efficient acid gas treatment processes.

Selective H2S Absorption Using the Mixture of NaOH-NaHCO3-Na2CO3 Buffer Solvent Solution

Acid gas enrichment unit (AGEU) involves selective separation of H2S from acid gas mixture, for example using absorption with an NaOH solvent solution. Sodium carbonate (Na2CO3) and sodium bicarbonate (NaHCO3) buffer addition to NaOH solution suppresses CO2 absorption, thereby increasing the selectivity of H2S absorption. This study evaluated the effect of buffer addition to increase H2S absorption selectivity using an NaOH solution. It was shown that both buffer addition and L/G ratio decrease could increase H2S selectivity by limiting CO2 absorption. Based on the simulation results, in the 0.006 to 0.030 L/G ratio range and NaOH solvent concentration greater than 2%-mass, the addition of NaHCO3 with mass ratio greater than 1.5:1 to NaOH and the addition of Na2CO3 at 1.26 times NaHCO3’s mass increased H2S absorption selectivity up to 17.3%. The combination of an L/G ratio of 0.006 and solvent with a composition of 5%-mass NaOH, 15%-mass NaHCO3, and 18.9%-mass Na2CO3 produced the highest H2S selectivity of 23.1 (379.7% H2S selectivity increase).

Prediction of vapour-liquid equilibrium ratios for the CH<SUB align="right">4-CO<SUB align="right">2-H<SUB align="right">2S systems using artificial neural networks

Acid gas removal is an important part of natural gas processing which is designed based on the type and concentration of impurities and the final specifications for the outlet gas. The typical process for removing acid gas involves their absorption from natural gas into a regenerative solvent. The efficiency of this process is affected by the mass transfer process between gas and liquid phases; so, it is necessary to study the phase equilibrium encountered in acid gas mixtures at different pressures and temperatures. In this work, an artificial neural network (ANN) has been developed to predict the vapour-liquid equilibrium ratio (KLV) for the CH4-CO2-H2S binary and ternary systems. Results show that a neural-network-based method provides an accurate estimation (93-98%) of KLV while considering all affecting parameters, compared to limited reported correlations. This work can be considered as an introduction to using ANNs for predicting the physical properties of mixtures. [Received: March 7, 2020; Accepted: March 10, 2021]

COMPARATIVE STUDY OF EMPIRICAL CORRELATIONS AND EQUATIONS OF STATE EFFECTIVENESS FOR COMPRESSIBILITY FACTOR OF NATURAL GAS DETERMINATION

Introduction: Today, there are four main groups of methods for calculating the compressibility factor of natural gas: experimental measurements, equations of state, empirical correlations, modern methods based on genetic algorithms, neural networks, atomistic modeling (Monte Carlo method and molecular dynamics). A correctly chosen method can improve the accuracy of calculating gas reserves and predicting its production and processing. Aim: To find the optimal methods for calculating the z-factor following the characteristic thermobaric conditions. Methods: To determine the best method for calculating the compressibility factor, the effectiveness of using various empirical correlations and equations of state to predict the compressibility factor of hydrocarbon systems (reservoir gases and separation gases) of various compositions were evaluated by comparing numerical results with experimental data. Results and Discussion: Based on 824 experimental values of the compressibility factor for 235 various gas mixtures in the pressure range from 0.1 to 94 MPa and temperatures from 273 to 437 K, the optimal equation of state and empirical correlation dependence for accurate z-factor prediction was found. It is shown that for all gas mixtures the Peng-Robinson equation of state with the shift parameter and Brusilovsky equation of state allow achieving best results. For these methods, the average absolute relative error does not exceed 2%. Among the correlation dependences, the best results are shown by the Sanjari and Nemati Lay; Heidaryan, Moghadasi and Rahimi correlations with an error not exceeding 3%. Conclusions: It was found that for the proposed methods, the reduced pressure has a more significant effect on the accuracy of the calculated values than the reduced temperature. It is shown that when studying acid gas mixtures with a carbon dioxide content of more than 10%, the equations of state better describe the phase behavior of the system in comparison with empirical correlations.

Identifying and Engineering Bottlenecks of Autotrophic Isobutanol Formation in Recombinant C. ljungdahlii by Systemic Analysis.

Clostridium ljungdahlii (C. ljungdahlii, CLJU) is natively endowed producing acetic acid, 2,3-butandiol, and ethanol consuming gas mixtures of CO2, CO, and H2 (syngas). Here, we present the syngas-based isobutanol formation using C. ljungdahlii harboring the recombinant amplification of the “Ehrlich” pathway that converts intracellular KIV to isobutanol. Autotrophic isobutanol production was studied analyzing two different strains in 3-L gassed and stirred bioreactors. Physiological characterization was thoroughly applied together with metabolic profiling and flux balance analysis. Thereof, KIV and pyruvate supply were identified as key “bottlenecking” precursors limiting preliminary isobutanol formation in CLJU[KAIA] to 0.02 g L–1. Additional blocking of valine synthesis in CLJU[KAIA]:ilvE increased isobutanol production by factor 6.5 finally reaching 0.13 g L–1. Future metabolic engineering should focus on debottlenecking NADPH availability, whereas NADH supply is already equilibrated in the current generation of strains.

Modelling acid gas mixtures of polar aprotic solvents and CO2 with the Cubic Plus Association equation of state

The Cubic Plus Association (CPA) equation of state and the Soave–Redlich–Kwong (SRK) equation of state coupled to Mathias–Copeman and volume correction parameters were used to correlate the vapor pressures and densities of pure polar aprotic solvents (PAS). It is shown that the CPA model (with 2B scheme) performed better than CPA (with inert scheme), SRK and its modifications in all cases for vapor pressure and densities. The performance of two mixing rules, namely the van der Waals one–fluid (vdW1f) and the Huron–Vidal (HV) mixing rules, is evaluated for these models on correlating the bubble–point pressures of CO2 + PAS mixtures. The CPA–HV model performs best at several temperatures, with the global average absolute deviations equal to 7.2 % for CPA–HV, 8.1 % for CPA–vdW1f and 8.7 % for SRK–HV. No improvements were found in the performance of the CPA–vdW1f when the solvation between CO2 and PAS was accounted for regression of bubble–point pressures.

Multiphase flow behavior for acid-gas mixture and drilling fluid flow in vertical wellbore

The transition laws of multiphase flow in a wellbore during acid-gas mixture influx are important for the hydraulic parameters design and wellbore pressure control in acid gasfield drillings. Herein, the phase change of acid-gas mixture in a wellbore was investigated by the experimental analysis. The results indicate that the acid-gas mixture in the supercritical phase exists under conditions of certain wellbore temperature and pressure, which makes its physical properties change abruptly near the critical point. Moreover, considering the phase change and dissolution of acid-gas mixture in drilling fluids, the multiphase flow may go through in turn the single phase flow, supercritical-liquid two phase flow, liquid-liquid two phase flow and gas-liquid two phase flow (including bubbly flow, slug flow, churn flow and annular flow) with the mixed fluids rising from bottom hole to wellhead. Meanwhile, the flow transition criteria, drift flux models and friction factor calculating methods for this type of multiphase flow were proposed. Finally, the multiphase flow characteristics in a wellbore during acid-gas mixture influx were analyzed using the new method with an example. The results suggest that during the acid-gas mixture rising up along the wellbore, the flow pattern transforming from the supercritical-liquid two phase flow or the liquid-liquid two phase flow into gas-liquid two phase flow can cause a large volume expansion, increasing the blowout risk.

The solubility of acid gases in the ionic liquid [C8mim][PF6

ABSTRACTMixtures containing associating compounds, represent highly non-ideal phase behavior, due to the presence of powerful hydrogen bonding interactions. Up to now, several associating models such as SAFT variants have been applied to such systems. The CPA EoS was introduced by Kontogeorgis and his coworkers in order to combine a cubic EoS, and the SAFT theory. At the present survey, acid gas mixtures solubilities in IL [C8mim][PF6] has been thermodynamically modeled using CPA EoS. The AAD % for binary systems, including H2S+ IL and CO2+ IL are 8.74, 2.14 respectively. Moreover, for ternary systems AAD % is equal to 17.43.

The Impact of Vapor/Liquid-Equilibria Calculations on Scale-Prediction Modeling

Summary Vapor/liquid-equilibria (VLE) calculations, particularly involving the phase behavior of carbon dioxide (CO2) and hydrogen sulfide (H2S), are used in scale-prediction modeling. In this work, the impact of VLE calculations for CO2- and H2S-rich gas phases and for acid- and sour-gas mixtures on scale-prediction calculations is evaluated. Three equations of state (EOSs)—Soave-Redlich-Kwong (SRK) (Soave 1972), Peng-Robinson (PR) (Peng and Robinson 1976), and Valderrama-Patel-Teja (VPT) (Valderrama 1990)—are implemented in the Heriot-Watt model and used in VLE calculations. The solubility of single-component CO2 and H2S in water and the solubility of a gas mixture in water were compared with experimental data in terms of the absolute relative deviation (ARD). The solubility data were then used in PHREEQC (USGS 2016) to calculate the impact of using different EOSs on carbonate and sulfide scales, particularly on calcium carbonate (CaCO3) and iron sulfide (FeS). Average ARDs of 6.04, 4.10, and 3.77% between experimental and calculated values for CO2 solubility in water were obtained for the SRK, PR, and VPT EOSs, respectively. Similarly, for H2S solubility in water, average ARDs of 6.49, 6.66, and 6.48% were obtained for each EOS, respectively. For the solubility of sour- and acid-gas mixtures in water, average ARDs of 13.92, 13.25, and 10.78% were obtained, respectively. It has thus been concluded that the VPT EOS performs better than the SRK and PR EOSs in VLE calculations for the analyzed data. The errors introduced in VLE calculations have been found to impact the calculation of the amount of CaCO3 precipitated, with consequences for scale-inhibitor selection. Higher deviations were found in the amount of CaCO3 precipitation for gas mixtures when compared with a single-component, CO2-rich phase. Furthermore, the large errors occurring in VLE calculations for H2S solubility have not been found to impact the calculation of the amount of FeS precipitated when H2S is in excess with respect to Fe2+. In addition to this, a case study that was performed by use of formation-water data from the Brazilian presalt revealed that the choice of EOS can cause errors of 6 kg of precipitate during each day of production. Scale-prediction calculations carried out with PHREEQC demonstrate that VLE calculations can have a high impact on mineral precipitation. Thus, it is recommended that the best VLE model available should always be used for scale-prediction modeling, particularly when mixtures of gases are present.

Integrating a compressible multicomponent two-phase flow into an existing reactive transport simulator

This work aims to incorporate compressible multiphase flow into the conventional reactive transport framework using an operator splitting approach. This new approach would allow us to retain the general paradigm of the flow module independent of the geochemical processes and to model complex multiphase chemical systems, conserving the versatile structure of conventional reactive transport. The phase flow formulation is employed to minimize the number of mass conservation nonlinear equations arising from the flow module. Applying appropriate equations of state facilitated precise descriptions of the compressible multicomponent phases, their thermodynamic properties and relevant fluxes.The proposed flow coupling method was implemented in the reactive transport software HYTEC. The entire framework preserves its flexibility for further numerical developments. The verification of the coupling was achieved by modeling a problem with a self-similar solution. The simulation of a 2D CO2-injection problem demonstrates the pertinent physical results and computational efficiency of this method. The coupling method was employed for modeling injection of acid gas mixture in carbonated reservoir.

Mineral trapping of a CO2/H2S mixture by hematite under initially dry hydrothermal conditions

For the experimental simulation of geochemical processes occurring in the vicinity of an injection well for CO2 with H2S impurities, the reaction of hematite with a CO2/H2S acid gas mixture in an initially water-free system was investigated. At the reaction conditions (120°C, 12MPa), a reductive dissolution of hematite and the successive precipitation of iron sulfide minerals pyrrhotite, marcasite and pyrite together with siderite were observed within days. Precipitation of secondary minerals presumably occurred either in the supercritical CO2 phase or, more likely, in an aqueous phase generated during the reaction progress due to the high initial H2S portion in CO2. The overall process can be described byFe2O3+2H2S+CO2→FeS2+FeCO3+2H2O.The observed process is relevant for the geologic co-storage of CO2 with H2S in sandstone formations with a substantial fraction of hematite (e.g. red-beds). There, mineral trapping of CO2 will be significantly promoted by reaction of co-injected H2S or SO2 with hematite – even in the dried-out zone near the injection well. This process can significantly impact the porosity of the storage rock due to an initial dissolution of hematite and subsequent deposition of secondary minerals with larger total volume. Hence, a plugging of pore throats appears to be feasible even in the desiccated zone in the vicinity of a CO2 or acid gas injection well.

Improving SO2capture by basic ionic liquids in an acid gas mixture (10% vol SO2) through tethering a formyl group to the anions

Novel formyl-containing task-specific ILs could be used to improve SO2capture under low SO2partial pressure.

A New Approach for Accurate Prediction of the Phase Behavior of the Complex Mixtures of Acid Gases, Hydrocarbons, Water, and Methanol in the Petroleum Industry

In this work a new approach for accurate prediction of the vapor-liquid equilibrium of the complex mixtures of water, methanol, acid gases (H2S, CO2), and hydrocarbons considering the hydrogen bonding association, hydrolytic dissociation, and acid gas solvation effects is presented. The overall average absolute deviation between the predicted and measured compositions regarding 330 sour gas mixtures is about 3.22%. The proposed CPA/electrolyte model is quite reliable over wide ranges of temperatures and sour gas concentrations and can be employed for accurate design of sour natural treatment and flow assurance systems in oil and gas industries.

High pressure measurements and molecular modeling of the water content of acid gas containing mixtures

Water content of three carbon dioxide containing natural gas mixtures in equilibrium with an aqueous phase was measured using a dynamic saturation method. Measurements were performed up to high temperatures (477.6 K = 400°F) and pressures (103.4 MPa = 15,000 psia). The perturbed chain form of the statistical associating fluid theory was applied to predict water content of pure carbon dioxide (CO2), hydrogen sulfide (H2S), nitrous oxide (N2O), nitrogen (N2), and argon (Ar) systems. The theory application was also extended to model water content of acid gas mixtures containing methane (CH4). To model accurately the liquid‐liquid equilibrium at subcritical conditions, cross association between CO2, H2S, and water was included. The agreement between the model predictions and experimental data measured in this work was found to be good up to high temperatures and pressures. © 2015 American Institute of Chemical Engineers AIChE J, 61: 3038–3052, 2015

Modelling phase equilibria for acid gas mixtures using the CPA equation of state. Part VI. Multicomponent mixtures with glycols relevant to oil and gas and to liquid or supercritical CO2 transport applications

In this work the Cubic Plus Association (CPA) equation of state is applied to multicomponent mixtures containing CO2 with alkanes, water, and glycols. Various modelling approaches are used i.e. different association schemes for pure CO2 (assuming that it is a non-associating compound, or that it is a self-associating fluid with two, three or four association sites) and different possibilities for modelling mixtures of CO2 with other hydrogen bonding fluids (only use of one interaction parameter kij or assuming cross association interactions and obtaining the relevant parameters either via a combining rule or using an experimental value for the cross association energy). Initially, new binary interaction parameters were estimated for (CO2+glycol) binary mixtures. Having the binary parameters from the binary systems, the model was applied in a predictive way (i.e. no parameters were adjusted to data on ternary and multicomponent mixtures) to model the phase behaviour of ternary and quaternary systems with CO2 and glycols. It is concluded that CPA performs satisfactorily for most multicomponent systems considered. Some differences between the various modelling approaches are observed.This work is the last part of a series of studies, which aim to arrive in a single “engineering approach” for applying CPA to acid gas mixtures, without introducing significant changes to the model. An overall assessment, based also on the obtained results of this series (Tsivintzelis et al., 2010, 2011, 2014, 2015, 2015), which is based on an investigation of about 30 multicomponent systems containing acid gases, water, alcohols, glycols and hydrocarbons, reveals that assuming cross association (solvation) of CO2 with glycols, alcohols and water or alternatively considering CO2 to be a self-associating molecule (with three or four sites) are the better approaches which perform similarly and quite satisfactorily. However, the use of the former one (solvation), using whenever possible experimental values for the cross association energy, in all cases is recommended.

Modelling phase equilibria for acid gas mixtures using the CPA equation of state. Part V: Multicomponent mixtures containing CO2 and alcohols

The Cubic plus association (CPA) equation of state has been previously applied to a variety of binary systems containing CO2 with alkanes, water, alcohols and glycols as well as a few multicomponent mixtures (with triethylene glycol, water and methane). In this study, we evaluate the performance of CPA for ternary and multicomponent CO2 mixtures containing alcohols (methanol, ethanol or propanol) water and hydrocarbons. This work belongs to a series of studies aiming to arrive in a single “engineering approach” for applying CPA to acid gas mixtures, without introducing significant changes to the model. In this direction, CPA results were obtained using various approaches, i.e. different association schemes for pure CO2 (assuming that it is a non-associating compound, or that it is a self-associating fluid with two, three or four association sites) and different possibilities for modelling mixtures of CO2 with water and alcohols (only use of one interaction parameter kij or assuming cross-association interactions and obtaining the relevant parameters either via a combining rule or using an experimental value for the cross-association energy). It is concluded that CPA is a powerful model that can be used for predictions of multicomponent mixture properties using no adjustable parameters fitted to the multicomponent system data. The results are satisfactory and rather similar with most investigated approaches. However, an overall assessment, also based on the obtained results of this series of studies [Tsivintzelis et al. Fluid Phase Equilib. 306 (2011) 38–56, J. Chem. Eng. Data 59 (2014) 2955–2972, Fluid Phase Equilib. 397 (2015) 1–17], reveals that the best approaches are those where the cross-association (solvation) of CO2 with alcohols and water is explicitly accounted for or alternatively when CO2 is considered to be a self-associating molecule (with three or four sites). Furthermore, it is recommended to use the experimental values of the cross-association energy for CO2–water and CO2–alcohols.

Modeling phase equilibria for acid gas mixtures using the CPA equation of state. Part IV. Applications to mixtures of CO2 with alkanes

The thermodynamic properties of pure gaseous, liquid or supercritical CO2 and CO2 mixtures with hydrocarbons and other compounds such as water, alcohols, and glycols are very important in many processes in the oil and gas industry. Design of such processes requires use of accurate thermodynamic models, capable of predicting the complex phase behavior of multicomponent mixtures as well as their volumetric properties. In this direction, over the last several years, the cubic-plus-association (CPA) thermodynamic model has been successfully used for describing volumetric properties and phase behavior of several mixtures of interest in oil and gas industry.The purpose of this work is to evaluate the performance of CPA for CO2–alkane mixtures. CPA calculations were performed using different association schemes for CO2. Firstly, CO2 was treated as non-associating fluid and, at a second level, CO2 was treated as self associating fluid, using the 2B, 3B and 4C association schemes. A systematic investigation of the CPA performance in correlating the phase behavior of CO2–alkane mixtures has been performed. Mixtures with alkanes up to n-hexatriacontane (n-C36) were investigated and the corresponding binary interaction parameters were estimated with all modeling approaches for CO2. CPA parameters were previously available for alkanes up to n-eicosane (n-C20) and new parameters have been estimated for heavier alkanes based on DIPPR correlations. CPA correlations were compared with literature experimental data for three heavy alkanes and a satisfactory agreement was observed. The CPA performance is discussed including trends of the interaction parameters with chain length and comparison to literature studies.