Phase behaviour and physical properties of reservoir fluids under addition of carbon dioxide

Abstract

The phase behaviour of reservoir fluids under the addition of carbon dioxide (CO2) were studied at elevated pressures and temperatures similar to those encountered in enhanced oil recovery (EOR) and carbon storage processes. The principal focus of the work presented in this thesis is the experimental investigation of the phase behaviour of these CO2 mixtures with hydrocarbon reservoir fluids. For this purpose, a new high-pressure high-temperature apparatus was designed and constructed. The apparatus consisted of a thermostated variable-volume view cell driven by a computer-controlled servo motor system. The maximum operating pressure and temperature were 40 MPa and 473.15 K, respectively. Measurements were then made over a wide range of pressure and temperature conditions for two representative CO2-hydrocarbon systems: (CO2 + n-heptane + methylbenzene) and (CO2 + synthetic crude oil). The vapour-liquid phase behaviour of the former system was studied, under CO2 addition and various molar ratios of n-heptane to methylbenzene, along different isotherms at temperatures between (298 and 473) K and at pressures up to approximately 16 MPa. In the latter, the synthetic oil contained a total of 17 components while solution gas (methane, ethane and propane) was added to obtain live synthetic crudes with gas-oil ratios of either 58 or 160. Phase equilibrium and density measurements were then made for the ‘dead’ oil and the two ‘live’ oils under the addition of CO2. The measurements were carried out at temperatures between (298.15 and 423.15) K and at pressures up to 36 MPa, and included vapour-liquid, liquid-liquid and vapour-liquid-liquid equilibrium conditions. The phase equilibria of (carbon dioxide + n-heptane + water) and (carbon dioxide + methane + water) mixtures were also studied using a high pressure quasi-static analytical apparatus with on-line compositional analysis by gas chromatography. The former system was studied under conditions of three-phase equilibria along five isotherms at temperatures from (323.15 to 413.15) K and at pressures up to the upper critical end point (UCEP). In the latter system, compositions of three coexisting fluid phases have been obtained along eight isotherms at temperatures from (285.15 to 303.5) K and at pressures up to either the UCEP or up to the hydrate formation locus. Compositions of coexisting vapour and liquid phases have been obtained along three isotherms at temperatures from (323.15 to 423.15) K and pressures up to 20 MPa for mixtures containing nearly equal overall mole fractions of CH4 and CO2. The quadruple curve along which hydrate coexists with the three fluid phases was also measured. A detailed study of these ternary mixtures was carried out based on comparison with available ternary data of the type (CO2 + n-alkane + water) and available data for the constituent binary subsystems. In this way, we analyze the observed effects on the solubility when the n-alkane component was changed or a third component was added. The experimental data for the (CO2 + hydrocarbon) systems have been compared with results calculated with two predictive models, PPR78 and PR2SRK, based on Peng-Robinson 78 (PR78) and Soave-Redlich-Kwong (SRK) cubic equations of state (EoS) with group-contribution formula for the binary interaction parameters and with the use of different alpha functions. Careful attention was paid to the critical constants and acentric factor of high molar-mass components. The use of the Boston-Mathias modification of the PR78 and SRK equations was also investigated. The experimental data obtained for the (CO2 + n-heptane + methylbenzene) mixture were also compared with the predictions made using SAFT-Gamma-Mie, a group-contribution version of the Statistical Associating Fluid Theory (SAFT), which was implemented with the generalized Mie potential to represent segment-segment interactions. Detailed assessment of the predictive capability of these models concluded that the agreement between the experimental data and prediction from these methods, while not perfect, is very good, especially on the bubble curve. The results suggest that there is merit in the approach of combining these methods with a group-contribution scheme. Comparison between these approaches concluded that they all have comparable accuracies regarding VLE calculations. The experimental data obtained for the ternary mixtures (CO2 + n-alkane + water) have been compared with the predictions of SAFT for potentials of variable range (SAFT-VR), implemented with the square-well (SW) potential using parameters fitted to experimental pure-component and binary-mixture data. A good performance of the SAFT-VR equation in predicting the phase behaviour at different temperatures was observed even with the use of temperature-independent binary interaction parameters. It was also observed that an accurate prediction of phase behaviour at conditions close to criticality cannot be accomplished by mean-field based theories, such as the models used in this work, that do not incorporate long-range density fluctuations. Density measurements on a variety of brines (both single-salt and mixed) were studied in the present work within the context of CO2 storage processes in saline aquifers. Densities of MgCl2(aq), CaCl2(aq), KI(aq), NaCl(aq), KCl(aq), AlCl3(aq), SrCl2(aq), Na2SO4(aq), NaHCO3(aq) , the mixed salt system [(1 – x) NaCl + xKCl](aq) and the synthetic reservoir brine system [x1NaCl + x2KCl + x3MgCl2 + x4CaCl2 + x5SrCl2 + x6Na2SO4 + x7NaHCO3](aq), where x denotes mole fraction, were studied at temperatures between (283 and 473) K and pressures up to 68.5 MPa. The measurements were performed with a vibrating-tube densimeter calibrated under vacuum and with pure water over the full ranges of pressure and temperature investigated. It was observed that careful attention needs to be paid to the type of calibration method selected. An empirical correlation is reported that represents the density for each brine system as a function of temperature, pressure and molality with absolute average relative deviations (%AAD) of approximately 0.02 %. Comparing the model with a large database of results from the literature suggested that the model is in good agreement with most of the available data. The model can be used to calculate density, apparent molar volume and isothermal compressibility of single component salt solutions over the full ranges of temperature, pressure and molality studied. An ideal mixing rule for the density of a mixed electrolyte solution was tested against our mixed salts data and was found to offer good predictions at all conditions studied with an absolute average relative deviation of 0.05 %. The present work was carried out as part of the Qatar Carbonates and Carbon Storage Research Centre (QCCSRC) program. It covered a wide range of phase behaviour and density measurements at conditions relevant to oil and gas fields’ applications, and explored the predictive capabilities of some available models, in particular predictive cubic EoS, SAFT-VR and SAFT-Gamma-Mie. The research and data collected represents a good step in enabling the direct design and optimisation of CO2-EOR and carbon storage processes. An example is the validation of the predictive models and the determination of the miscibility pressure which is essential for effective recovery of the heavy hydrocarbons. Areas in which the research might be extended, both through further experimental studies and improved modelling, have been identified.