The calculation of pressure drop resulting from the flow of oil through porous media or pipes requires the evaluation of viscosity. This is the single most important transport property necessary to calculate pressure drop accurately. The basis for oil-viscosity calculations using a traditional black-oil approach is the determination of dead-or gas-free-oil viscosity.A total of 23 dead-oil-viscosity calculation methods have been identified from the literature and evaluated in this paper. A large database consisting of data from conventional pressure/volume/ temperature (PVT) reports, crude-oil assays, and the literature was compiled from more than 3,000 samples from around the world. The number of actual viscosity measurements exceeded 9,800. An evaluation of the correlations yielded unacceptable results largely because of the failure of the methods to properly account for the physics of the problem. In general, this results from the methods' failure to properly account for the change in viscosity with temperature and to address the chemical nature of the oil. A significant improvement in results can be realized through the use of the Watson characterization factor in addition to oil API gravity and temperature in the correlation of viscosity. This work has identified the character of the crude to have a significant effect on oil viscosity, especially for oils with gravities less than 25°API.Methods have been proposed in the literature that use the Watson characterization factor; however, these have been largely ignored in the upstream oil industry. Therefore, a new method has been developed that shows significant improvement over existing methods. At reservoir conditions, a 2-to 13-fold reduction in average absolute error was noted when compared with the error observed from traditional methods. At surface process conditions, this improvement ranged 3-to 60-fold. In addition, an updated correlation for Watson characterization has been developed. The ASTM density correction for varying temperature has been examined. Revised coefficients were developed that enhance the method's accuracy for both oils and pure components and provide a suitable means to convert kinematic viscosity to absolute viscosity. DatabaseIn order to ascertain the accuracy of the published dead-oil-viscosity methods and the supporting auxiliary relationships, a database was developed. Data from conventional oil PVT reports, from crude-oil assays, and pure-component data were included in the database, which encompassed the following ranges of properties shown in A total of 9,837 viscosity measurements from 3,047 fluid samples are present in the database, representing samples from many of the major producing basins around the world. For many of the fluid samples, viscosity was measured at several temperatures, which helps to validate the measurement and ensure that this behavior is correlated properly. Auxiliary RelationshipsThe development of a relationship to calculate dead-oil viscosity requires methods to reliably determine fluid properties, s...

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For live crude oils, dissolved gas acts to reduce viscosity from the value observed for dead oils. The reduction in viscosity can significantly impact pressure drop and flow rate and must be properly accounted for by any viscosity model. This article provides a detailed review of existing correlation methods and offers state-of-the-art solutions necessary for oil field operations in 2007 and beyond. A total of 21 methods for calculating saturated oil viscosity have been identified from the literature. A large database consisting of data from oil PVT reports and literature sources has been compiled in order to evaluate these methods. This data represents over 12,000 measurements from 1849 samples. The gases dissolved in the oils contain varying amounts of non-hydrocarbons and the oils provide a representative crossection of the expected range in API gravity and Watson characterization factor found in crude oils from producing regions located around the world. A detailed analysis of correlation performance has been conducted which reveals inaccuracies in many of the previously published methods. As a result, a new method is proposed which is consistent across a wide range of parameters and offers increased accuracy over existing methods. Introduction Viscosity is the single most important parameter for calculating the pressure drop of fluids flowing through pipe or porous media. The viscosity of the crude oil is affected by the composition of the oil (specific gravity and characterization factor), solution gas-oil ratio, pressure and temperature. Three distinct areas are identified: dead or gas free, saturated, and undersaturated. Fig. 1 shows the viscosity behavior of a crude oil with each area identified. Starting from a dead condition, free gas in contact with the oil dissolves into the oil with increasing pressure until all of the gas is in solution at the bubblepoint. As the gas dissolves in the oil, the density and viscosity of the oil are reduced. Above the bubblepoint, viscosity increases in the undersaturated region due solely to the effect of pressure on the oil. Bergman and Sutton5,6 have provided a detailed review of the dead and undersaturated regions including accurate methods to determine viscosity in each region.

As the petroleum industry accesses more low-gravity-oil resources, modification of viscosity by blending lighter hydrocarbons has become a necessity in order to attain bulk properties that will flow though a pipeline. In the more conventional oil reservoirs, the need to estimate the viscosity of oil blends occurs when reservoir fluids are contaminated with oil-based muds or when production streams from different reservoirs or fields are commingled in a single pipeline. Several methods have appeared in the literature for estimating blend viscosity. All of these methods require a measured viscosity for each component of the blend. The number of viscosity measurements is compounded when the viscosity of the blended mixture is required at several temperatures. Of the viscosity correlations published, the Bergman and Sutton method has the widest range of temperature and oil API gravity and has been consistently demonstrated to provide accurate results over these conditions. This method requires the component specific gravity, the Watson characterization factor (Watson K factor), and temperature to estimate viscosity. By using the proper mixing rules, an estimate of blend viscosity can be made with comparable or improved accuracy over the "best" published methods without the need for individual-component viscosity measurements. A database of 2,059 blend-viscosity measurements from more than 800 mixtures was created to compare the accuracy of the various methods. Viscosity measurements of the individual components in the blends studied exceeded 7,600 data points. A diverse group of mixtures, ranging from light alkane or aromatic pure components to bitumen, diesel, biodiesel, condensate, crude, and assay fractions, was included in this database. Blends comprised the typical binary mixtures but ranged up to a maximum of eight components in the mixture.

Summary This paper presents an experimental study involving a series of hydrocarbonmiscible displacements of a crude oil. Compositional analyses of both flowingeffluent phases show that most of the oil was recovered by the condensing-drivemechanism. High mobile water saturations in the highly water-wet Berea coresused led to the same oil-trapping phenomena as noted for CO2 displacements. Introduction Benham et al. and others described a process by which a rich injection gaswould displace a relatively lean oil by the condensing-drive mechanism. In thisprocess, the oil gradually becomes enriched by intermediate components thatcondense out of the injection gas. Eventually, the multiple-contacting processthat occurs in the reservoir enriches the oil to the point where it is misciblewith the injection gas, and a zone of contiguously miscible fluids from theoriginal oil to the injection gas forms. Fig. 1 is a ternary-diagramrepresentation of the fluid compositions that occur during this process. Thedotted line represents the overall composition path of the produced fluids, andthe solid curves are the composition of the coexisting produced vapor andliquid phases, which are joined by the tie-lines. The condensing-drive processcreated a transition zone of fluid compositions, which progress from reservoiroil through a two-phase region to a critical point and formally to theinjected-gas composition. The important feature of this diagram is that, as theliquid phase becomes more and more enriched, the coexisting liquid and vaporphases approach each other at a critical point near the injected-fluidcomposition. Recently, Zick proposed that not all rich-gas/real-oil systemscould develop miscibility by the condensing-drive mechanism. Instead, heproposed a condensing/vaporizing mechanism. In this mechanism, intermediatecomponents initially condense from the injection gas into the oil, as Benham etal. proposed. Alter the oil becomes saturated with the intermediates from theinjection gas, however, condensation ceases. Instead, vaporization of heavierintermediates from the enriched oil to fresh injection gas occurs, and themechanism changes to a vaporizing drive similar to that occurring during CO2 floods. The injection gas, now enriched with heavier intermediates from theoil, moves ahead to contact fresh oil and begins the condensing process again. In this condensing/vaporizing process, thermodynamic miscibility might never beestablished even though oil recovery can be quite high. Fig. 2 is a ternaryrepresentation of the condensing/vaporizing process. Here, the oil and gascompositions start to approach each other, as in the condensing process, but atsome point vaporization begins and the compositions begin to diverge. Thus, nocritical point is encountered and thermodynamic miscibility is not established. Studies reporting this vaporizing/condensing mechanism for a rich-gas floodwere based on computer modeling studies and laboratory mixing-cell experiments. The water-alternate-gas (WAG) injection process has been used in pilot andfield-scale enhanced-gas-drive floods to control the inherently poor mobilityratio between the injected gas and in-place oil. This injection technique isbelieved to improve the sweep efficiency of injected solvent, thereby improvingutilization of this relatively expensive fluid. WAG can lead to high mobilewater saturations, particularly in previously waterflooded reservoirs. Previousstudies, primarily emphasizing first contact-miscible (FCM) and multiplecontact-miscible (MCM) systems with CO2, where miscibility develops by avaporizing process, have shown that the in-place oil can be shielded from theinjected solvent by mobile water in water-wet porous media. This prevents theinjected solvent from contacting and displacing part of the residual oil inlaboratory systems. Shielding is either much less severe or nonexistent inoil-wet porous media. The purposes of this study were to determine thefollowing.Whether the rich-gas displacement mechanism in a long corefloodis a classic miscible condensing process or whether a condensing/vaporizingprocess occurs.The amount of oil recovered by vaporization, if it occurs.Whether high mobile water saturation in rich-gas floods results insignificantly different oil-trapping behavior in a water-wet core than MCM CO2 or FCM systems.The effect of long contact time on trapped oil recovery bydiffusion across the trapping water boundary. Experimental Three types of displacement tests were conducted during this study:slim-tube tests and two types of long Berea core tests. Slim-tube tests wereconducted to measure the minimum miscibility pressure (MMP) with proceduresdiscussed elsewhere. Briefly, to obtain the MMP from a series of slim-tubedisplacements, oil recovery is plotted vs. run pressure. Recovery typicallyincreases with increasing pressure until a maximum recovery is obtained. Further increase in pressure results in little, if any, additional increase inoil recovery. This point of maximum recovery (or breakover torn in therecovery-vs.-pressure plot is the MMP. This point of miscibility has been foundto correlate with changes in sight-glass observations for MCM CO2 displacementsin which miscibility is developed by a vaporization or extraction process. Inone type of Berea core test, the effluents were collected at high pressure andthen analyzed after completion of the flood to study the rich-gas displacementmechanism. Fig. 3 is a schematic of the coreflood apparatus used to collectproduced fluids at test conditions. Each collected sample contains about 90cm3, or 0.05 PV, of fluid for subsequent PVT analyses. Additional corefloods tostudy water-shielding effects were conducted with a similar apparatus in whichthe produced fluids were flashed to atmospheric conditions rather thancollected at high pressure. More details on procedures for these 2-in. [5.1cm]-diameter Berea core tests are found elsewhere. All tests were conducted at135F [57.2C], and the corefloods were conducted at 2,000 psi [13.8 MPa]. Table1 presents compositions and fluid properties of the injection gas, recombinedreservoir crude oil, and brine used in all the tests. Also, Fig. 4 shows apressure-vs.-composition (bulk mole fraction solvent) phase diagram of thecrude oil and rich-gas solvent.