Viscosity, Density, and Composition Measurements of CO2/West Texas Oil Systems
- R.M. Lansangan (New Mexico Petroleum Recovery Research Center) | J.L. Smith (New Mexico Inst. of Mining & Technology)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1993
- Document Type
- Journal Paper
- 175 - 182
- 1993. Society of Petroleum Engineers
- 5.2.2 Fluid Modeling, Equations of State, 4.1.5 Processing Equipment, 5.4.2 Gas Injection Methods, 4.1.2 Separation and Treating, 5.1 Reservoir Characterisation, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4 Enhanced Recovery, 4.6 Natural Gas, 5.1.1 Exploration, Development, Structural Geology, 5.4.9 Miscible Methods, 5.7.2 Recovery Factors, 5.4.10 Microbial Methods, 5.2 Reservoir Fluid Dynamics, 5.2.1 Phase Behavior and PVT Measurements, 5.5 Reservoir Simulation
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Shear viscosity coefficients, volumetric properties, and equilibrium-phase compositions for CO2/West Texas oil mixtures are presented. Effects of solution gas, nitrogen in the CO2 stream, and viscosity dependence on phase density and CO2 concentration also are examined. The work shows that measured CO2-rich phase viscosities increased as solution gas in the oil increased. Nitrogen in the CO2 stream results in lower CO2-rich phase viscosities and densities compared with those from an identical run with pure CO2 solvent. CO2/crude-oil viscosity measurements reveal viscosity and density behavior patterns that are unique to these systems. Undersaturated CO2/crude-oil mixtures show an abnormal viscosity dependence on density. The viscosities show a monotonic decrease, while the densities increase with continued dilution of the oil with CO2. The equilibrium vapor (dense fluid) and liquid phases, however, exhibit normal viscosity/density behavior. Data are compared with a popular reservoir-fluid-viscosity correlation commonly used to estimate CO2/crude-oil viscosities in reservoir simulation studies. We show that the correlation cannot predict CO2/crude-oil-system viscosities accurately.
CO2/crude-oil-system phase behavior has been investigated extensively.1-3 The data generated from these studies show the phase-behavior and fluid-property effects on local displacement efficiency, which are important for understanding displacement mechanisms involved in CO2 flooding processes. Knowledge of the fluid-phase equilibria that evolve in such processes is required to evaluate how viscous fingering, gravity segregation, hydrodynamic dispersion, and interfacial-tension phenomena affect laboratory coreflood results and pilot field studies. Furthermore, mixtures of CO2 and most naturally occurring crude oils exhibit complex phase-behavior topography, especially around the CO2-critical-point vicinity.1,4-8
Thermodynamic and transport property data on well-defined CO2/hydrocarbon mixtures are widely available. This information is essential for obtaining binary interaction parameters for equation-of-state (EOS) modeling purposes, but it is not useful for inferring crude-oil mixture properties primarily because of inherent uncertainties in the oil makeup for C7+ components. Correlational packages based on the limited information available could be developed that allow reasonably accurate estimation of the desired properties over a wide range of conditions.
It is well-established that "impurities" in the CO2 stream can affect the pressure requirement [minimum miscibility pressure (MMP)], which affects miscibility development and recovery. Hydrogen sulfide and hydrocarbon components heavier than ethane lower the MMP, while the addition of methane to the CO2 stream increases the miscibility pressure requirement. The effect of impurities on the physical properties of the phases that evolve during dynamic miscibility development is not as well-documented. It is important to understand the physical changes that occur because of their potential impact on process recovery efficiency.
We undertook an extensive study to develop a comprehensive database that relates viscosity to density and composition of single and equilibrium dense-fluid and liquid phases for CO2/crude-oil systems. Currently, theoretical development and modeling of the condensed phase of matter does not allow a complete understanding of the momentum transfer mechanism, even for simple Newtonian flow behavior. We present information that can be used to evaluate future predictive viscosity models for the liquid and dense-fluid phases. The database can be used to develop a correlation that can be applied in compositional reservoir simulations to estimate the oil viscosity and in-situ CO2/oil mixtures.
We present the results of phase-behavior and fluid-property measurements of CO2/West Texas crude-oil systems. The experiments were performed over conditions ranging from 105 to 165°F and from 1,200 to 2,350 psia. A continuous multiple-contact apparatus, the continuous phase equilibrium (CPE) apparatus, was used for on-line density and viscosity measurements of a single homogeneous phase or two coexisting phases. Equilibrium-phase compositions, densities, and viscosities were measured for all the crude oils with pure CO2 injection at the slim-tube-measured MMP and the corresponding reservoir temperature whenever applicable.
The composition of one oil was deliberately altered to assess the effect of light-hydrocarbon presence on the physical properties of the oil and CO2/oil mixtures. Another experiment was performed to determine the effect of small amounts of N2 in the CO2 stream on the properties of the impure CO2/crude-oil mixtures.
We attempted to explain the observed viscosity/density behavior qualitatively in terms of molecular association caused by strong intermolecular Coulombic interactions between CO2 and hydrocarbon molecules. Finally, we demonstrate that the Lohrenz, Bray, and Clark9 (LBC) viscosity correlation cannot estimate the viscosities of the mixtures studied with reasonable engineering accuracy.
Refs. 10 and 11 describe the experimental apparatus used in this study in detail. The CPE apparatus measures physical properties and compositions of a single phase or two coexisting phases under isothermal and isobaric conditions while overall mixture composition continuously varies. Experimentally defined phase boundaries are depicted most conveniently with a pseudoternary phase diagram. Orr and Silva10 and Lansangan et al.11 discussed the inherent differences between the CPE and a conventional static-equilibrium apparatus in detail.
The dynamic nature of the CPE apparatus results from continuous introduction of a high-pressure solvent (CO2, for instance) into a mixing vessel first charged with the oil at the run pressure. The solvent and oil are brought into single-phase homogeneity or two-phase equilibrium rapidly by circulating pumps that provide mechanical agitation. Isobaric conditions are maintained by backpressure regulators that allow fluid sample collection from the top and the bottom of the vertically oriented mixing vessel. Separate density, viscosity, and composition measuring devices are installed downstream of the upper and lower sample ports to allow simultaneous property and composition measurements of two coexisting phases.
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