No abstract

This paper was prepared for presentation at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, 28-31 March 1999.

A difficulty in modeling multicontact miscibility processes is achievement of consistent, stable convergence of gas and oil phase compositions, densities, and viscosities as the critical point is approached. The use of an equation of state offers the advantage of a single, consistent source of calculating K-values and phase densities. The criterion of stable convergence viscosity in the vicinity of critical regions is not often met without fine tuning with laboratory data as phase viscosity correlations are usually developed independent of each other. The present study extends the van der Waals model to viscosity by drawing an analogy between the graphs of PVT and PμT. Vapor and liquid viscosities based solely upon pure component critical data and acentric factor were derived from the Lawal-Lake-Silberberg (LLS) equation of state for methane through eicosane, i-butane, neo-pentane, carbon dioxide, and nitrogen. The 6718 experimental data used cover a range of temperatures from −183°F to 482°F and pressure up to 20,000 psia. For the twenty-four components, the average absolute deviation of the predicted viscosities from experimental is 5.9%. A mixing rule which relates mixture parameters to composition and pure component constants is proposed and comparisons of 9,000 experimental data with computed viscosities for several binary, multicomponents, natural gases and complex systems resulted in an average absolute deviation of 3.5%. The extension of the mixing rules to predictions of reservoir oil viscosity was generally within +8% of the experimental values. Extensive comparisons of the LLS viscosity equation with other methods of predicting reservoir oil viscosity are made and found to be generally superior in ease of use and in accuracy. The prediction of vapor and liquid viscosities from the LLS equation of state makes the present work very attractive for compositional reservoir simulators and other applications which are repetitive in nature. The use of an equation of state to predict phase viscosities offers an opportunity to make calculations in the critical region without the computational problems commonly associated with that effort. The internal consistency and the convergence of vapor and liquid viscosities at the critical point have heretofore been unattainable.

In support of the research project at the Center for Applied Petrophysical and Reservoir Studies in geologic storage of carbon dioxide in depleted gas reservoirs, the PVT laboratory at Texas Tech University performed compressibility factor (z-factor) measurements at various composition of CO2 with hydrocarbon (HC) gas mixture. For the sole purpose of the measured Z-factor data, three temperatures of 100°F, 160°F and 220°F and pressures ranges from 50 psia to 5000 psia are selected as representative of the depleted gas reservoirs (DGRs). In order to analyze the various phase behavior to be encountered in gas reservoirs (dry gas, wet gas and retrograde gas), the median gas compositions for dry, wet and retrograde gases are specified by gas type. The gas types are categorized by representative compositional analysis for the three types of gas reservoirs (dry gas, wet gas and retrograde gas). The measurements of z-factors for CO2-hydrocarbon mixtures in varying proportions and at the three specified temperatures for various pressures are performed on the median gas compositions of the type gases. The results of the z-factor measurements of CO2-hydrocarbon mixtures are used to interpret the expected phase behavior to be encountered in the geologic storage of CO2 in gas reservoirs. Also, the z-factor measurements of CO2-retrograde gas mixtures are used to quality the benefits of enhanced gas and condensate recovery in gas reservoirs. Introduction Since the earlier 1970, carbon dioxide has been used for enhanced oil recovery through miscible and immiscible displacement of oil at high pressures and moderate temperatures. Recently, research is being directed for the use of carbon dioxide in the oil refining through supercritical extraction of hydrocarbons.1 Current activities are to find ways for geologic storage of CO2 in oil or gas reservoirs.2 Although one laboratory measurement of CO2-hydrocarbon mixture in the limited ranges of temperatures and pressures used in this project has been reported in Venezuela (Rojas-Requena, 1992),3 this paper presents experimental measurements of z-factors for CO2-hydrocarbon mixtures at three specified temperatures and pressures ranging from 50 psia to 5000 psia. The results of the experimental z-factors are used to quantify economic benefits (such as enhanced oil recovery (EOR) and enhanced condensate vaporization) of geologic storage of CO2 in gas reservoir. Procedure for Z-factor Determination The compressibility factor, or Z-factor, is determined by manipulating the Real Gas Law and assuming that reservoir gas will behaves as an ideal gas at ambient pressure and temperature (McCain, 1990, page 106). The Real Gas Law is defined as follows:Equation 1 For a constant composition system, the product of pressure and volume is constant, thusEquation 2 Where the subscripts are:Condition in the cellAmbient condition

The purpose of this paper is to investigate the effects of phase behavior on the sequestration CO2 of in depleted gas reservoirs (dry gas, wet gas and retrograde gas). Carbon dioxide sequestration in depleted and abandoned gas reservoirs can accomplish two important objectives. Firstly, it could be important part of present climate control initiative to reduce the concentration of carbon dioxide in the atmosphere. Secondly, it could be instrumental to enhance gas and condensate recovery. Using the pressure-temperature diagrams and two phase flash calculations, the phase behavior of natural gas-carbon dioxide mixtures were analyzed to provide enlightenment on the sequestration process. From analysis of simulated results, it was found that carbon dioxide exhibited a drying effect on wet and retrograde gas mixtures and a wetting effect on dry gas. The results for retrograde gas condensate depended on the composition of reservoir fluids at abandonment conditions. The main difference being the liquid volume present with increasing pressure and carbon dioxide concentration. This influenced the volume of condensate vaporized with addition of carbon dioxide. It was also determined that carbon dioxide lowers the compressibility factor of all gas types. These results are favorable for carbon dioxide sequestration because decreasing compressibility factors represents increasing storage capacity. Introduction In the year 2000, the fossil fuel combustion in the U.S. accounted for the release of approximately 114.1 trillion cubic feet1 of carbon dioxide (CO2) to the atmosphere. The volume of carbon dioxide emitted has increased steadily since the industrial era leading to concerns of global warming and the ensuing climatic changes. Sequestration of carbon dioxide in depleted gas reservoirs, with storage capacity estimated to be 140 GtC (Gigatonnes Carbon) worldwide,2 is considered as a possible solution. Problem Description The sequestration of carbon dioxide in depleted gas reservoirs results in contact and eventual mixing between carbon dioxide and natural gas. Early in the sequestration process, portions of the reservoir contain pure natural gas, mixtures of natural gas and carbon dioxide, and pure carbon dioxide. Eventually the entire reservoir becomes a homogeneous mixture of the two fluids. Before there is complete mixing of natural gas and injected carbon dioxide within the reservoir, there is variation of carbon dioxide concentration in the reservoir. Analyzing the phase behavior of sequestration aids in understanding how the properties of natural gas vary with carbon dioxide concentration of a homogeneous mixture and can be extended for known compositional gradients. In planning geologic sequestration projects of depleted gas reservoirs, it is important to know how natural gas behaves under reservoir conditions when carbon dioxide is injected into the reservoir. In particular, the compressibility factor (Zfactor) of the gas phase and the amount of liquid present at reservoir and surface conditions are particularly useful in predicting phase behavior, enhanced gas and condensate recovery. Predictions and analysis of the phase behavior of carbon dioxide-natural gas mixtures in depleted gas reservoirs, account for the physical characteristics of the in situ natural gas, the injected gas at reservoir conditions, and the consequent gas mixture. Phase behavior of the fluids involved in sequestration is investigated as a function of pressure, temperature and gas composition. By this means it is possible to give a more accurate estimate of the volume of sequestered carbon dioxide, enhanced gas production and enhanced condensate production that can be sequestered in a particular reservoir. This is a crucial guideline in sequestration development schemes when considering enhanced gas and condensate recovery. By using this approach, assessing a depleted gas reservoir as a candidate for carbon dioxide sequestration based on temperature, pressure and gas type is necessary.