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Abstract This paper describes research in modeling unstable displacement processes (especially related to the application of CO2 flooding) with the ultimate goal of predicting recoveries in unstable field scale displacements. The research has focused on understanding and quantifying the effects of process parameters, such as reservoir heterogeneity, phase behavior, fluid properties, and solvent/water injection ratio, on the stability of displacements. Numerical simulation using very fine grids was used to obtain these results. These fine grid simulations were compared to simulations using the more standard models based on the mixing parameter concept of Todd and Longstaff and the theory of Koval. This work produced the following observations:In secondary miscible displacements in heterogeneous reservoirs, the value of the mixing parameter can be strongly dependent on mobility ratio. In displacements which are not first contact miscible, the shockfront mobility ratio is generally less than the fluid viscosity ratio. This effect tends to stabilize the displacement front. The mixing parameter model can, in some cases, be used to model such processes, and the value of the mixing parameter can be estimated from knowledge of the mobility ratio across the displacement front. In general, for displacements which are not first contact miscible, the mixing parameter model is inadequate due to its inability to account for thermodynamic nonequilibrium between zones of oil contacted and uncontacted by solvent. In tertiary displacements the frontal mobility ratios, as computed from a one-dimensional solution, are in general not sufficient to compute the stability of the displacement. Introduction The current state of the art for miscible flood modeling uses the mixing parameter model of Todd and Longstaff or and equivalent, such as the model of Koval, to represent the effects of frontal instability and heterogeneity on displacement efficiency. These models represent the region of chaotic frontal disturbance as a region of mixed displacing and displaced fluid of continuously varying concentration, and compute the mobilities of the two fluids using a segregated flow model with modified viscosities. Such a model is, in general, necessary because of the extremely small size scale of the intrusions of displacing fluid into the displaced fluid and the consequent large computational effort required of a more detailed representation of the fluid distribution. It is the purpose of this paper to present results of research aimed at developing an understanding, quantitative when possible, of the limits of mixing parameter models, and of how the value of the mixing parameter depends on parameters governing the displacement process. Such information is of evident use in designing and optimizing miscible flood processes. P. 187^
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Multiphase equilibrium calculations for binary, ternary, and quaternary hydrocarbon-water systems at high temperature were performed using the Schmidtz-Wenzel equation of state. The solubility of water in the hydrocarbon-itch liquid phase and vapor phases is modelled using a constant binary interaction parameter between water and hydrocarbon, while the solubility of hydrocarbons in the aqueous phase is calculated using a temperature dependent binary interaction parameter. Two and three phase equilibrium calculations were performed using the method of successive substitution. A stability analysis using the tangent plane criterion was used to determine the correct number of phases present. At high temperature the solubility of water in hydrocarbon liquids can be quite large. Using the procedure outlined above the solubility of water in the hydrocarbon-itch liquid phase was calculated accurately both for mixtures of water and pure hydrocarbon components, and for mixtures of water and petroleum fractions. The binary interaction parameters used in the hydrocarbon-rich liquid phase and the vapor phase were found to be dependent on the type of hydrocarbon. The interaction parameters for components in the same homologous group such as alkanes, aromatics, and alkenes were found to be almost the same. The solubility of hydrocarbons in the aqueous phase was calculated reasonably accurately using temperature dependent interaction coefficients in the aqueous phase. Above 200 the binary interaction parameters in the aqueous phase were linear functions of temperature. Binary interaction parameters from two phase binary data were found to be quite adequate to calculate three phase multicomponent equilibrium. Introduction Three phase equilibrium calculations with hydrocarbon and water phases are required in the modelling of many reservoir processes. At low temperatures, the solubility of water in the hydrocarbon-rich liquid phase and the solubility of hydrocarbon components in the aqueous phase is small. Thus the hydrocarbon phases and the water phase can be treated as being completely immiscible for the purposes of modelling without introducing significant error. At high temperatures, however, the solubility of water in the hydrocarbon-rich liquid phase can be quite large and the solubility of light hydrocarbons and acid gases in the aqueous phase is appreciable. Hoot and Brady et al. have given experimental data for the solubility of water in pure hydrocarbon components and petroleum fractions at the three phase pressure as a function of temperature. The solubility of water in hydrocarbon liquids increases exponentially with temperature, and at temperatures above 500F, it can be as high as 40 mole %. The solubility of water in hydrocarbons is primarily dependent on the temperature and the paraffin/aromatic characteristics of the hydrocarbons with only a slight effect of carbon number and molecular weights. The solubility of water at a given temperature is the lowest in alkanes and napthenes and the highest in aromatics, particularly benzene (see Figs. 1 and 2). The solubility of water in alkenes lies between its solubility in alkanes and aromatics. The solubility of hydrocarbons in water is considerably less than the solubility of water in hydrocarbons. At high temperature, the solubility of light hydrocarbon components such as methane and acid gas components such as CO2 and H2S can be greater than 10 mole %. The solubility of hydrocarbons in water drops off sharply with increased molecular weight. Given approximate equivalence of molecular weight, alkanes, then alkenes, then napthenes, and finally aromatics are progressively more soluble in water. Several papers in the literature deal with the modelling of hydrocarbon-water systems using equations of state (EOS). Heidemann used the Wilson modification of the Redlich-Kwong EOS to perform three phase flash calculations for hydrocarbon-water systems at temperatures below 300F. The calculation DID procedure was based on the minimization of the Gibbs free energy of the system by integration along the path of steepest descent. Heidemann's scheme used the component material balances and iterated on the component compositions in each phase so that the Gibbs energy of the system was minimized. He tested his procedure by modelling a three component and a six component system. Heidemann used a constant interaction parameter in all phases and was able to match the water content of the hydrocarbon liquid and vapor phases reasonably well. However, the predicted solubility of hydrocarbons in the aqueous phase was orders of magnitude too low. The efficiency of the method was poor, and a large number of iterations were necessary to obtain convergence. P. 733^
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
Abstract A major objective of low-tension, surfactant-polymer flooding is the design of surfactants for high-salinity reservoirs. In this technology the irreducible oil Saturation, hence the recoverable oil, depends on the interfacial tension between the aqueous and oleic phases. In the three phase systems that are usually employed, the "oil-water" tension depends on the thermodynamic distance of the system from a tricritical point, which is a point where all three of the phases become a (t - Ttc) where T is the reservoir temperature and Ttc is the temperature of the tricritical point. Hence, optimal high-salinity surfactant design requires the ability to create systems with tricritical points at temperatures and salinities that are set by each individual oil reservoir. The development of this ability requires methods for the prediction and control of the locations of tricritical prediction and control of the locations of tricritical points. points. Tricritical points can only occur in phase diagrams with at least four dimensions, which makes their study difficult. Many of these difficulties can be overcome by means of a step-by-step consideration of critical points and phase behavior in diagrams of lower points and phase behavior in diagrams of lower dimensionalities. A step-by-step approach to tricritical points and lines is described. Analysis of existing data shows that tricritical points of commonly used "cosurfactants" (alcohols and points of commonly used "cosurfactants" (alcohols and nonionic surfactants) are at "negative" reservoir salinities. For such materials interfacial tensions must inevitably increase and oil recoveries fall as they are used in reservoirs of increasing salinity, even if the "optimal salinity" of the surfactant matches the salinity of the reservoir in all cases. Addition of an ionic surfactant (eg, petroleum sulfonate) creates a tricritical point at zero (rather than negative) salinity, but this amount of improvement is too small to be satisfactory. In the most desireable behavior, the lines of critical endpoints converge with increasing salinity and the tricritical points are at positive, controllable salinities. For this behavior optimal interfacial tensions decrease and oil recoveries can increase as the surfactants are used in reservoirs of greater and greater salinity. Surfactant designers should measure and report critical endpoints at different temperatures (not just optimal salinities at a single temperature), so that the thermodynamic limits on high-salinity surfactants can be better ascertained. Introduction The recent report of the National Petroleum Council on Enhanced oil Recovery (EOR) concludes that the greatest promise for the commercialization of chemical-flood EOR lies in the development of advanced technology. One of the advances called for in the report is the development of surfactants that will produce ultralow interfacial tensions in high-salinity reservoirs, but the report does not suggest how these materials can be designed. This paper discusses recent advances in the understanding paper discusses recent advances in the understanding of tricritical points and surfactant phase behavior that should prove very useful to anyone who is interested in this very important and difficult materials question. Section II briefly reviews fundamental relationships among waterflood-residual oil saturations, capillary numbers, and critical points. An important reason for choosing three-phase conditions is suggested. Section III summarizes the phase behavior and critical point nomenclature of surfactant/oil/water systems and their trigonal prism temperature/composition phase diagrams. P. 441
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
Abstract The Camurlu oil field, operated by the Turkish Petroleum Corporation (T.P.A.O.) in Southeast Turkey, Petroleum Corporation (T.P.A.O.) in Southeast Turkey, contains roughly 60 millions m3 (380 MMbbl) of a low gravity oil (10-12M API) A the "Alt Sinan" formation. The poor quality of the oil, the heterogeneity of the reservoir and the presence of a large gas cap are responsible for the low primary recovery estimated at less than 1%. The "Mus" formation, located beneath the oilbearing reservoir, contains a CO 2- rich natural gas 73%). In 1983, these facts have led TPAO and the Institut Francais du Petrole to evaluate the stimulation of oil production wells with the CO2-rich gas using the Huff n'Puff technique. Two production wells, located as far as possible from the gas cap were selected at first. The tests which started in 1984, consisted in the injection of a limited amount of CO2 (11 MMscf) followed by a short soaking time and a subsequent back-production. Early oil production figures showed a mom "an 5 fold increase over figures obtained prior CO2 injection. prior CO2 injection. This paper presents the results obtained on the two wells selected for the pilot test. Up to now two cycles of injection-production in each well have been performed. Finally, the planned extension of the project to other wells is presented. Introduction The CAMURLU Oil field, operated by the Turkish Petroleum Corporation (T.P.A.O) in Southeast Turkey Petroleum Corporation (T.P.A.O) in Southeast Turkey (Fig. 1) contains roughly 60 millions m3 (380 MMbbl) of a low gravity oil (10-12deg. API) in the Alt Sinan Formation. The poor quality of the oil, the heterogeneity of the reservoir and the presence of a large gas cap are responsible for the low primary recovery estimated at less than 1%. (1) The "Mus" formation, located beneath the oil-bearing reservoir, contains a CO 2- rich natural gas (73%). The situation led T.P.A.0 and Institut Francais du Petrole (I.F.P.) to consider improving the oil recovery by using the CO 2- rich gas from the underlying Mus formation. First of all laboratory studies were performed both A the Research Center of T.P.A.O. and I.F.P. to evaluate the properties of the gas and the effect of this gas on the oil properties (Swelling, Viscosity reduction). A review of the reservoirs showed that the eastern part of the Alt Sinan formation was the most suitable for the pilot test. The evaluation of the Mus formation showed that the productivity potential was sufficient to deliver the amount of gas potential was sufficient to deliver the amount of gas required for the project, at the appropriate daily rate. The project consisted in the injection of a limited amount Of CO2 (10 MMscf) followed by a short soaking time and a subsequent back production. The major part of the field application has been undertaken by T.P.A.O. which was responsible for all field activities including well workovers, stimulations and testing. P. 247
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (3 more...)
Abstract Adsorption values for mono-isomerically pure nonionic surfactants are shown here to depend upon the phase properties of the surfactant in aqueous solution. When the experimental conditions are referenced to the temperature at which the solution being employed phase separates, the adsorption values over a range of temperature, brine salinities and surfactant concentrations are observed to follow a consistent trend. This correlation is observed to be consistent for six surfactant molecules, over a range of solubility balance, both with and without aromatic rings. The observations reported here indicate that for applications requiring a particular optimal temperature, large linear ethoxylated alcohols are preferred to either smaller molecules or phenolic species. Introduction One factor which has a large impact on the economic viability of micellar polymer flooding is surfactant loss. Reduction in the amount of surfactant required can turn a marginal project into a good one. The same is true of surfactant-generated foams. Modern micellar design methodology requires that the process run in and/or pass through the 'optimal' phase behavior region. Thus, surfactant selection is constrained by attaining the highest solubilization-at-optimum at conditions attainable in a given reservoir - otherwise, the process will not mobilize oil. Within this constraint, minimization of surfactant loss is highly desirable. The only variable available for adjustment is, however, surfactant structure. Many reservoirs contain harsh brines which are not amenable to sulfonates. Thus, the motivation for consideration of nonionic surfactants is their insensitivity to such harsh brines, by which we mean that they remain soluble and have less tendency to precipitate than sulfonates. Prior literature alludes to unacceptably high adsorption as a downfall of these materials. In a previous publication, we showed that the adsorption losses publication, we showed that the adsorption losses for nonionic surfactants were comparable to those for sulfonates as long as the nonionics were not used at temperatures too close to their 'cloud points' (it will be shown here that consideration points' (it will be shown here that consideration of the entire phase boundary curve is more precise). The main thrust of the work being precise). The main thrust of the work being presented here is to demonstrate how changes in presented here is to demonstrate how changes in surfactant molecular structure can be used to reduce adsorption while maintaining, or actually increasing, the solubilization parameter. Commercial nonionic surfactants, often polyethoxylates or propoxylates, are diverse mixtures polyethoxylates or propoxylates, are diverse mixtures of species. Lipophiles range from fairly narrow to fairly broad distributions, while hydrophiles are generally Poisson distributions of ethylene oxide numbers. Since our desire here is to correlate adsorption to molecular structure, we have chosen to work with single-specie (monodisperse) nonionic surfactants. This choice facilitates interpretation of our results. No work is presented here for any surfactant mixtures. Schechter and coworkers (c.f. Ref. 3) have investigated the effect of sulfonate lipophile structure on adsorption of sulfonated surfactants. Unfortunately, much of their work is at conditions where these molecules would not be effective at mobilizing oil (sub-optimal). Their work has also been conducted with well-characterized (molecularly pure) materials. Such materials are required in pure) materials. Such materials are required in order to look at lipophile structure because most commercially synthesized sulfonates are too molecularly diverse to allow unambiguous interpretation. Several general results for nonionic surfactant adsorption are found in the literature. At constant salinity, adsorption increases with increasing temperature. At fixed temperature, adsorption increases with increased salinity. P. 389
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
SPE Members Abstract A new high pressure visual cell made of Sapphire has been developed to determine minimum dynamic miscibility pressures (MDMP). The pressure rating of this cell is 50 MPa (7250 psia) at 420 K (300 deg. F). The minimum dynamic miscibility pressure for the system methane-propane-n-decane has been determined using this cell. The MMP is determined by visual observations of droplets of gas passing through the reservoir fluid. By multiple contact between the injected gas and the reservoir fluid the injected gas will dissolve in the reservoir fluid at the MDMP. During the experiment the volumes and compositions of the gas and liquid phases are determined. The duration of such experiment is hours. A comparison between the experimental phase behaviour and the calculated results using the Peng-Robinson Equation of State is given. The phase Peng-Robinson Equation of State is given. The phase characterization of the Equation of State developed from these experiments is different from the phase match characterization developed from the usual pVT experiments. Simulations of slim tube displacements using the two different characterizations are compared. The simulation of the slim-tube displacements using the phase match based on multiple contact experiments (MDMP's from the Sapphire cell) gives the best overall match of the slim-tube displacements. Introduction The ultimate goal in an enhanced oil recovery process is to displace oil and produce it process is to displace oil and produce it economically. To accomplish this one must understand the relationship between phase behaviour, miscibility and displacement efficiency. The phase behaviour, especially in the near critical region, has a strong influence on the displacement pressure and injection gas composition required for miscibility. This relationship has been well documented. The most common procedures used to experimentally determine the conditions required for miscibility are pVT experiments and slim tube displacement experiments. describing the phase behaviour is to create a characterization of the reservoir fluid and match (tune) the phase behaviour from pVT experiments with an Equation of State. This phase match is then tested to see how accurately it allows a reservoir simulator to model the slim tube displacement experiments. P. 67
SPE Member Abstract 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 PPT. Vapor and liquid viscosities based solely upon pure component critical data and eccentric pure component critical data and eccentric 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 -183deg.F to 482deg.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 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 predictors of reservoir oil viscosity was generally within +B% 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 predict phase viscosities offers an opportunity to make calculations in the critical region without the computational problems commonly associated with that 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. P. 43
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
Abstract This study correlates the phase behavior of surfactant/oil/brine systems with their chemical flood performance in short cores. The study focuses on the influence of two important system composition variables: viz. the brine salinity and the nominal equivalent weight of a petroleum sulfonate blend. Furthermore, it investigates the influence of the addition of an alkylether sulfate in terms of optimal salinities, increased salinity tolerance and tertiary recovery efficiency. The oil displacement experiments employ a very fast, near-continuous, constant salinity flooding process in 3-inch long Berea cores, using a process in 3-inch long Berea cores, using a microwave instrument to determine the oil saturations. A typical turn-around time for a flooding experiment was seven hours. Tertiary oil recovery contours are developed in a brine salinity-surfactant equivalent weight space. The region of highest tertiary oil recovery in that space closely matched the region in which equilibrium three-phase systems existed. Optimal salinities are equivalent weights, as defined by the chemical flood with the lowest final oil saturation, were obtained with excellent resolution. More significantly, they closely matched those optimal values obtained under equilibrium conditions from time-consuming solubilization parameter measurements. parameter measurements. The addition of the alkylether sulfate solubilizer had the effects of increasing the optimal salinity, and significantly broadening the three-phase region as well as the region of high tertiary oil recovery. This broadening effect caused a lower resolution in the determination of optimal system variables. In the presence of the solubilizer, a close correspondence between the three-phase region and the region of optimum oil recovery was also observed. This study introduces a rapid and meaningful technique to determine the EOR potential of surfactants and surfactant formulations. Applications of the results of this work include: the rapid screening of surfactants for enhanced oil recovery processes in specific rock matrices, the design and optimization of surfactant formulations and the quality control of plant-manufactured surfactants and field-blended surfactant formulations. Introduction The screening and selection of surfactant candidates for possible use in a chemical flooding operation is a multi-tiered process, governed by both economic and technical considerations. From an economic point of view, surfactant cost and availability are the two major considerations. From a technical point of view, it is generally recognized that a proposed surfactant or surfactant formulation should, as a minimum requirement, be able to reduce the tension, under field conditions, between the injected solution and the oil in place. This reduction in the tension should be sufficient to either eliminate or significantly reduce the capillary forces which have trapped the oil in the formation. In addition to tension reduction, a number of other criteria are taken into account in the process of selecting, designing and optimizing a process of selecting, designing and optimizing a surfactant system. Surfactant loss, due to adsorption onto the rock or due to other retention mechanisms such as phase entrapment during a chemical flood, should be minimized because it can otherwise be detrimental to the efficacy of the injected formulation. The stability and effectiveness of the surfactant should be ascertained in brines with the salinities and divalent cation concentrations likely to be encountered in the formation in question. P. 311
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- North America > United States > California (0.28)
Abstract The results of laboratory research conducted to study displacement of crude oil by high-pressure nitrogen injection are presented in this paper. The objectives of this research were to study the effect of temperature and original gas-oil ratio in solution on crude oil recovery and the miscibility process in high-pressure (H-P) nitrogen injection. Also in addition, the effectiveness of nitrogen injection after waterflooding and the effect of nitrogen-driven propane slugs was examined. Nine experimental tests were propane slugs was examined. Nine experimental tests were performed using crude oil of 42.3 API recombined with performed using crude oil of 42.3 API recombined with natural gas. The experimental tests were made using two temperatures (70F and 120F) and three gas-oil ratios in solution (575 SCF/STB, 400 SCF/STB and 200 SCF/STB). The reservoir model used was a stainless steel tube 125 feet long and 0.435 inches in diameter, packed with sand consolidated to give an average packed with sand consolidated to give an average permeability of 910 md. The model was provided with five permeability of 910 md. The model was provided with five sampling valves to collect vapor samples. The vapor samples were analyzed by using a gas chromatograph. A temperature control system was built based on the results obtained from a heat transfer mathematical model specifically prepared for this research. The results obtained in this study suggest very strongly that crude oil recovery and miscibility in this kind of oil depend on temperature and oil-gas ratio in solution. Multiple-regression equations to predict crude oil recovery using temperature and gas-oil ration in solution were developed based on the experimental data. Introduction A relatively new process of vaporization gas drive, the application of high-pressure nitrogen (N) injection to increase ultimate production, has been receiving special attention because of the high cost and limited supply of natural gas. The main goal of injection of N2 is to achieve miscibility with the reservoir fluid. The miscibility obtained by nitrogen injection in a light crude oil reservoir is a conditional miscibility; where the fluids are not miscibles on the first contact, but form two phases, with one of the fluids absorbing components from the other. After sufficient contacts and exchange of components, the system becomes miscible. N2 -light crude oil miscibility phenomenon is complex and depends on the composition of the reservoir fluid, temperature, pressure, as well as other factors such as interphase mass transfer, effect of relative permeability, capillary pressure and gravity. This research is the continuation of an investigation conducted by Tarek Ahmed and Donald Menzie (1983). These researchers studied the displacement of light crude oil by nitrogen at different injection pressures at room temperature and using a constant gas pressures at room temperature and using a constant gas oil ratio in solution. The primary objectives of this research are:Formulation and preparation of a computer program to simulate the heat transfer process in the physical model, To confirm the validity of the data obtained by various researchers using the same physical model, Injection of nitrogen into the reservoir model at one pressure and different temperatures, Injection of nitrogen into the reservoir model at one pressure above the miscibility pressure and different pressure above the miscibility pressure and different solution gas-oil ratio to study the effect of the gas-oil solution on oil recovery, miscibility and track the compositional changes taking place during displacement, Run a regular waterflood and then displace nitrogen to study if miscibility is obtained under those conditions, and Run a nitrogen-driven propane slug test to study the possibility for future propane slug test to study the possibility for future investigation of using the same laboratory equipment. Literature Review In 1928, Power performed a laboratory study to determine whether air is superior to natural gas as a driving medium or vice versa. Power also used nitrogen in his experiments. P. 383
- North America > United States > Texas > Permian Basin > Central Basin > Block 31 Field > Ellenburger Formation (0.99)
- North America > United States > Oklahoma > South Lone Elm Field (0.99)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
Whitson, C.H., Consultant Member SPE-AIME Abstract This paper describes a new method for calculating critical properties of petroleum fractions used as input to a cubic equation of state (EOS). The method differs from existing methods in that it forces the EOS to match measured values of boiling point and molar volume (molecular weight divided point and molar volume (molecular weight divided by specific gravity) for each petroleum fraction. PVT predictions are made with the proposed method using the Peng/Robinson EOS for selected reservoir fluids reported in the literature. Saturation pressure and saturated density are calculated with the EOS and compared with experimentally determined values. Heptanes-plus (C7+) fractions are characterized using the proposed method and results indicate that both proposed method and results indicate that both volumetric and phase behavior are improved. Reservoir fluids used in the study represent a wide range of compositions with PVT properties reported at temperatures ranging from 38–120 C. A new method is suggested for matching experimental saturation pressure with an EOS. Using the proposed method for calculating critical properties, the boiling point of the heaviest properties, the boiling point of the heaviest petroleum fraction is adjusted until mixture petroleum fraction is adjusted until mixture saturation pressure is matched. A near-linear relation exists between boiling point of the heaviest fraction and saturation pressure. It is suggested that this method has more physical meaning than the common practice of adjusting methane binary interaction coefficients. Proposed methods can be used with any cubic EOS. Critical properties are presented graphically for the Peng/Robinson and Soave/Redlich/Kwong equations. A generalized form of the two-constant cubic EOS is proposed, and necessary expressions for phase and volumetric calculations me given. The critical-property method is diagrammed schematically to facilitate programming. It can be easily incorporated into existing PVT software already based on an EOS. Introduction Cubic equations of state are used to calculate volumetric and phase behavior of petroleum reservoir fluids. input data required by an equation of state (EOS) usually includes critical pressure, critical temperature, and acentric pressure, critical temperature, and acentric factor of each component in the mixture. For pure compounds these properties are known. Critical properties must be estimated for the petroleum properties must be estimated for the petroleum fractions making up heptanes-plus. Having defined critical properties for all the components in a mixture the EOS can be used to predict PVT properties. properties. This paper proposes a new method for calculating critical properties of petroleum fractions. The method requires normal boiling point and molar volume for each petroleum point and molar volume for each petroleum fraction. The EOS chosen is forced to fit the boiling point and molar volume by adjusting critical pressure and critical temperature. Acentric factor is estimated by an empirical correlation using boiling point and molar volume; this correlation is general and does not depend on the EOS. Whitson reviews the most common empirical correlations used for estimating critical properties of petroleum fractions. He studies the properties of petroleum fractions. He studies the effect of C7+ characterization on EOS predictions and concludes that none of the existing correlations gives consistently better PVT predictions. Observations from this earlier work predictions. Observations from this earlier work led to the idea that an alternative approach could be used for defining critical properties of individual petroleum fractions based on the EOS used for mixture calculations. P. 59