bluuebunny/crossref_metadata_2025_split huggingface dataset:
Phase Equilibria in CO2—Multicomponent Hydrocarbon Systems: Experimental Data and an Improved Prediction Technique
Authors: Turek Edward A. , Metcalfe Robert S. , Yarborough Lyman , Robinson Robert L. 
Published: December 2007

Abstract
Numerical simulation of miscible EOR processes requires calculation of the phase equilibria that exist between solvent and oil over the entire solvent/oil composition range. One calculation approach is to tabulate K-values from experimental data and allow the simulator to access the table when necessary. This approach can lead to erroneous conclusions for CO2 miscible processes if there are insufficient tabulated phase equilibrium data to cover all possible compositions, in particular those cases where three phases exist at some point in the displacement.
This paper presents a different approach to the problem. If a generalized equation of state (EOS) can match experimental data, then it can be used in a reservoir simulator to calculate the phase equilibria necessary for the prediction of fluid compositions, densities, and viscosities during a displacement process. Previous work has shown how a generalized Redlich-Kwong equation can be used to calculate typical hydrocarbon phase behavior relationships that exist in condensate and black oil reservoir systems. The equation parameters have been modified further for use in hydrocarbon/CO2 calculations over a wide range of CO2 concentrations.
Appropriate mixing rules for description of the phase equilibria in CO2/hydrocarbon systems have been developed. Experimental binary vapor/liquid equilibrium (VLE) data have been used to evaluate the constants in the EOS for pure CO2 as well as interaction terms used within the mixing rules. Predictions of phase equilibria then have been made and compared with experimental data for a synthetic multicomponent hydrocarbon/CO2 system and a crude oil/CO2 system.
Simulation of Miscible Displacement in Full-Diameter Carbonate Cores
Authors: Batycky J. P. , Maini B. B. , Fisher D. B. 
Published: December 2007

Abstract
Miscible gas displacement data obtained from full-diameter carbonate reservoir cores have been fitted to a modified miscible flow dispersion-capacitance model. Starting with earlier approaches, we have synthesized an algorithm that provides rapid and accurate determination of the three parameters included in the model: the dispersion coefficient, the flowing fraction of displaceable volume, and the rate constant for mass transfer between flowing and stagnant volumes. Quality of fit is verified with a finite-difference simulation.
The dependencies of the three parameters have been evaluated as functions of the displacement velocity and of the water saturation within four carbonate cores composed of various amounts of matrix, vug, and fracture porosity. Numerical simulation of a composite core made by stacking three of the individual cores has been compared with the experimental data.
For comparison, an analysis of Berea sandstone gas displacement also has been provided. Although the sandstone displays a minor dependence of gas recovery on water saturation, we found that the carbonate cores are strongly affected by water content. Such behavior would not be measurable if small carbonate samples that can reflect only matrix properties were used. This study therefore represents a significant assessment of the dispersion-capacitance model for carbonate cores and its ability to reflect changes in pore interconnectivity that accompany water saturation alteration.
Pressure Dynamics in Wells During Gas Kicks: Part 1 - Component Models and Results
Authors: Hoberock L.L. , Stanbery S.R. 
Published: December 2007

Summary
This is the second part of a theoretical study of the dynamic pressure and flow behavior of an onshore well containing a gas kick controlled by the driller's method. The main results from this study show that (1) casing pressure profiles under assumed constant bottomhole pressure can be very sensitive to both pump stroke variations and standpipe pressure variations, (2) the pressure time delay from casing choke to standpipe is extremely variable, (3) pressure changes rapidly as the gas begins to exit the choke, and (4) the effects of a sudden adjustment at the choke can be magnified at bottomhole, with the largest magnification occurring after the gas begins to exit the choke.

Introduction
In this paper, the proposed well model described in Part I is developed employing the transmission line solution techniques of Part 1. The final model is operated as a real-time, manually controlled simulator, whose outputs are compared with actual test well data.In Part 1, the development of the digital and analog solution techniques were based on the flow of a Newtonian fluid in a line of constant dross section and length. Thus, to use either of these techniques to represent the drillpipe and annular lines, it is necessary to account for the facts that the drilling mud is actually non-Newtonian and that the annular liquid lines are of time-varying lengths and annular cross section. In addition, to represent the two-phase fluid line, the fact that the fluid within this region is a gas/mud mixture with the gas rising at a velocity relative to the mud must be taken into account. Accordingly, the necessary modification to the basic solution techniques to model these effects and suitable models for the mud pump, casing choke, and drill bit are discussed.

Drillpipe Transmission Line
To account for the change in inner diameter between drillpipe and collars, it is necessary to model the drillpipe as two coupled fluid-line sections. However, in the specific test well installation that is modeled, there are no collar sections in the drillstring. Thus, it can be assumed that the drillstring is a single constant-length section of constant circular cross-sectional area.Within the range of drillpipe velocities encountered in practice, the most commonly used drilling muds frequently are modeled as nonNewtonian Bingham plastics. Accordingly, to use the solution techniques of Part 1 to predict pressure and flow propagation in the drillpipe, it is necessary to make suitable modifications to reflect the nonNewtonian nature of the drilling mud. It can be shown that the steady-state frictional pressure drop per unit length dp/dz for the flow of a Bingham plastic in a smooth circular pipe is given by
(1)
where p = fluid density, D = pipe diameter, U = mean fluid velocity, and f = Fanning friction factor.
Unlike the Newtonian case, however, the Fanning friction factor in Eq. 1 for a Bingham plastic is a function of the Bingham Reynolds number N and the Headstrom number NHe.
JPT
P. 1367^
Applications of Water-Soluble Polymers in the Oil Field
Authors: Chatterji J. , Borchardt J.K. 
Published: December 2007

Summary
Water-soluble polymers commonly used in the oil field are reviewed. The properties of guar, guar derivatives, cellulose derivatives, xanthan gum, locust bean gum, starches, and synthetic polymers, especially polyacrylamides, are discussed and related to chemical structures of the polymers. Original data comparing polymer solution viscosity properties under identical conditions are presented. These data include effect of polymer concentration on solution viscosity, temperature effect on solution viscosity, viscosity in acidic solution, and polymer solution viscosity in the presence of a hemicellulase enzyme.

Introduction
Water-soluble polymers are used extensively in various phases of drilling, completion, workover, and production of oil and gas wells. 1,2 In spite of widespread use, the connotation "polymers" (macromolecules) still confuses many people involved in oilfield work. This confusion is due in part to the wide variety of commercially available polymers, which are generally organic and have a carbon-based structure. The lack of understanding and appreciation of polymers and their properties severely restricts the selection of the best polymer for the particular application under consideration.
The purpose of this paper is to define clearly the commonly used but often misunderstood terminology. The paper defines the term polymer and distinguishes between homopolymers, copolymers, block copolymers, and graft copolymers. The chemical structures of most commonly used naturally occurring polymers, chemically modified naturally occurring polymers, and synthetic polymers are shown. Attempts are made to describe how physical and chemical properties of these organic polymers are regulated by their chemical structures. Use of these polymers in drilling, cementing, fracturing, acidizing, controlling water production, preventing sand production, clay stabilization, lost circulation, and enhanced recovery, where known, is described.

Polymer Definition
Ethylene gas (CH2=CH2, boiling point˜-152°F, molecular weight=28), under proper chemical conditions, will combine with hundreds or thousands of other ethylene molecules to form a solid product called polyethylene, with a molecular weight in the millions. This polymer is familiar to everyone as packaging film and can be seen at any supermarket meat counter. This conversion of ethylene to polyethylene is called polymerization - the chemical combination of many small molecules to form a very large molecule.3–6

Polymer Definition
Ethylene gas (CH2=CH2, boiling point˜-152°F, molecular weight=28), under proper chemical conditions, will combine with hundreds or thousands of other ethylene molecules to form a solid product called polyethylene, with a molecular weight in the millions. This polymer is familiar to everyone as packaging film and can be seen at any supermarket meat counter. This conversion of ethylene to polyethylene is called polymerization - the chemical combination of many small molecules to form a very large molecule.3–6
Linear Waterflood Behavior and End Effects in Water-Wet Porous Media
Authors: Kyte J.R. , Rapoport L.A. 
Published: December 2007

Introduction
Theory indicates that linear waterfloods should exhibit scaling and stabilization properties in both oil-wet and water-wet porous media. Experimental verification of these properties in oil-wet media was obtained some time ago, and more recently, Perkins employing a high permeability unconsolidated sand and a low oil-to-water viscosity ratio, has obtained flooding data in a water-wet medium which follow the pattern of scaling and stabilization. Also, Root and Calhoun have found similar trends in the displacement of gas by liquids from unconsolidated sands. In general, however, the experimental evidence appears still somewhat conflicting since scaling and stabilization of water floods in water-wet media has not been observed in most of the studies to date.
The purpose of this paper is to provide a more comprehensive picture of waterflood behavior in water wet media and to corroborate the validity of the scaling and stabilization concepts. The need for differentiating between the intrinsic nature of water-oil displacements inside a porous medium and perturbating secondary end effects is discussed, pertinent experimental procedures are outlined and the results of flooding tests conducted at low and at high oil-to-water viscosity ratios on consolidated, water-wet Alundum cores are analyzed.
Influence of Polymer-Molecule/Wall Interactions on Mobility Control
Authors: Duda J. L. , Klaus E. E. , Fan S. K. 
Published: December 2007

AbstractThis paper presents the results of a study of molecule/wall interactions on permeability modification of consolidated porous media by polymer solutions. The experiments were conducted with a newly developed low-shear porous media viscometer. This is a simple-to-use, versatile instrument that is particularly useful for measurements at the low shear rates characteristic of reservoir flooding. The key for obtaining reproducible, steadystate results was to expose the porous medium to several hundred pore volumes of polymer solution to saturate it with polymer. The effective permeability during polymer flow and the residual permeability were determined for xanthan gum and polyacrylamide solutions in Berea sandstone, Bradford sandstone, filter papers, and Nuclepore® filters. A mechanistic interpretation of the coupling of adsorption, mechanical entrapment, shear rate, and inaccessible pore volume effects on the effective and residual permeabilities was developed. This is the first study to show that inaccessible pore volume can influence the residual permeability significantly.
Compositional Modeling With an Equation of State
Authors: Nghiem L. X. , Fong D. K. , Aziz K. 
Published: December 2007

Abstract
This paper describes an implicit-pressure explicit-composition and explicit-saturation compositional model. The model uses an equation of state (Peng-Robinson) for phase equilibrium and density calculations. Interfacial tension effects are considered also. The formulation of the pressure equation yields a symmetric and diagonally dominant matrix that allows the use of the iterative conjugate gradient method for large systems. Simulation of laboratory CO2 displacements shows good agreement between calculated and experimental results. The influence of interfacial tension is investigated. Physically reasonable results also have been obtained for hypothetical areal and cross-sectional problems.
Microemulsion Phase Behavior-Observations, Thermodynamic Essentials, Mathematical Simulation
Authors: Bennett Karl E. , Phelps Craig H. K. , Davis H. Ted , Scriven L. E. 
Published: December 2007

Abstract
The phase behavior of microemulsions of brine, hydrocarbon, alcohol, and a pure alkyl aryl sulfonate—sodium 4-(1 -heptylnonyl)benzenesulfonate (SHBS or Texas 1)—was investigated as a function of the concentration of salt (NaCl, MgCl2, or CaCl2), the hydrocarbon (n-alkanes, octane to hexadecane), the alcohol (butyl and amyl isomers), the concentration of surfactant, and temperature. The phase behavior mimics that of similar systems with the commercial surfactant Witco TRS 10-80™. The phase volumes follow published trends, though with exceptions.
A mathematical framework is presented for modeling phase behavior in a manner consistent with the thermodynamically required critical tie lines and plait point progressions from the critical endpoints. Hand's scheme for modeling binodals and Pope and Nelson's approach to modeling the evolution of the surfactant-rich third phase are extended to satisfy these requirements.
An examination of model-generated progressions of ternary phase diagrams enhances understanding of the experimental data and reveals correlations of relative phase volumes (volume uptakes) with location of the mixing point (overall composition) relative to the height of the three-phase region and the locations of the critical tie lines (critical endpoints and conjugate phases). The correlations account, on thermodynamic grounds, for cases in which the surfactant is present in more than one phase or the phase volumes change discontinuously, both cases being observed in the experimental study.
Studies on Pilot Water Flooding
Authors: Rosenbaum M.J. Fischer , Matthews C.S. 
Published: December 2007

Abstract
The purpose of this work was to learn what in formation could be obtained from various types of pilot water floods and to attempt to find the optimum pilot pattern for a reservoir which had previously been depleted by a solution gas drive. The study was made in the laboratory with mathematical methods, a dynamic analog and a potentiometric analog. Results were tested against the field histories of a number of pilot water floods.
At a reasonable value of cumulative injection, the total production rate for the one-in factor five-spot should reach about 6.5 per cent of injection rate, and for a four-injector five-spot, about 9 per cent. Accurate estimates of ultimate recovery cannot be made on the basis of such small production rates. However, with a pilot composed of nine injectors and 16 producers, the production rate is approximately 50 per cent of injection rate at a reasonable value of cumulative injection. Some information for extended performance predictions high be obtained from such a large pilot.
These conclusions were drawn on the basis of results obtained for unit mobility ratio, and a study using the potentiometric analog was made of the effect of other mobility ratios to determine the range of applicability of these predictions. For the four-injector, five-spot pilot with Mw, o = 1/4, the ratio of production to injection rate (before water breakthrough) is about twice that for Mw, o = 1; with Mw, o = 4, it is about two-thirds; and with Mw, o = 10, it is about one-third. For high mobility ratios, it was found that the production rate increased considerably as water-cut increased. These results can be used to modify, qualitatively, the interpretations based on curves for the unit mobility ratio cases.
It was found that the maximum ratio of production rate to injection rate observed in field pilot floods was of the same order as that predicted by these methods. The time required to reach this maximum did not generally agree with the time predicted for a homogeneous reservoir. The difference between predicted and observed time of response gives an indication of the permeability profile and of the condition of the producing wells.
An Improved Summation-of-Fluids Porosity Technique
Authors: Hensel W. M. 
Published: December 2007

Abstract
The summation-of-fluids porosity technique is used widely throughout industry. While its primary value is associated with fast turnaround time for core data required for well control during drilling, the data frequently are used for reserves estimates, general reservoir engineering, and geological purposes. This paper describes an improved technique that provides a more precise determination of "pore water" to the exclusion of clay water, water of hydration, etc. This, in turn, can improve the accuracy of porosities and associated oil and water saturation values when expressed as fractions of the pore volume. The method determines the pore water at a stabilized furnace temperature of 350° F (177°C), which is below the thermal degradation temperature of common clays and minerals associated with most reservoir rocks, gypsum being a common exception. Case histories are shown where use of the 350°F (177°C) stabilized temperature method resulted in marked improvement in agreement of porosity data determined by Boyle's law and summation-of-fluids methods where previous lack of agreement existed using standard API procedures for measuring pore-water volumes.
Unified Analysis of Drawdown and Buildup Data for Physical Model Reservoir Flow With Producing Well at Center of Vertical Fracture
Authors: Jaggernauth D. J. , Lin Z. S. , Lescarboura J. A. , Bishop K. A. , Clark C. R. , Swift G. W. 
Published: December 2007

Abstract
A physical model of a gas reservoir having a vertical fracture with fracture half-length xf = 0.0635 m was developed. The model is a right circular cylinder of latex concrete with the radius xe = 0.305 m so that the xe/xf ratio is 4.8. The producing well is located at the center of the fracture. Experimental drawdown and buildup data taken from this reservoir were analyzed using available theoretical developments from the literature. The effect of pressure on permeability (the Klinkenberg effect) was included in the analysis. Simplex optimization was used in conjunction with unified (drawdown plus buildup) super-positioning to give fracture half-lengths of 0.0631 and 0.0635 m from two sets of experimental data. Corresponding values for permeability for these two sets of data were 0.0605 × 10−18 and 0.0624 × 10−18 m2, respectively, at a Klinkenberg coefficient of 5900 kPa. The fracture half-length and permeability are shown to be highly correlated. Thus, the results have more uncertainty than would be found in determining parameters by similar methods of analysis for an unfractured system. Bearing this in mind, the agreement between the known fracture half-length and values determined from the analysis of experimental data is excellent. Thus, we have demonstrated the utility of unified analysis as well as the ability to create an artificial fracture. Since the location of the model fracture relative to producing and observation wells is at the discretion of the designer, our model presents a unique opportunity to study various configurations which might be difficult to handle by mathematical modeling alone.
Interpreting Relative Permeability and Wettability From Unsteady-State Displacement Measurements
Authors: Batycky J. P. , McCaffery F. G. , Hodgins P. K. , Fisher D. B. 
Published: December 2007

Abstract
A procedure has been developed and tested for evaluating the capillary pressure and wetting properties of rock/fluid systems from unsteady-state displacement data such as that used for calculating two-phase relative permeability characteristics. Currently, the common practice is to conduct most coreflooding experiments so that the capillary pressure gradient in the direction of flow is small compared with the imposed pressure gradient. The proposed method, on the other hand, is based on performing low rate displacements during which capillary forces and, hence, end effects can influence the saturation distribution and pressure response of the core sample. Besides providing a means for monitoring capillary forces and wettability during the dynamic displacement test, the proposed method has the advantage of permitting the displacement tests to be conducted at rates more typical of those in the reservoir. Thus, it is possible to avoid potential problems such as fines migration and emulsion formation, and the method permits a realistic representation of transient interfacial effects that can be important with reservoir fluid systems and chemical flooding agents.
Specifically, the method involves performing low rate displacements between the irreducible-water and residual-oil endpoint saturations. Except for the added provision of stopping, restarting, and sometimes reversing the flow after the endpoints have been reached, these are routine unsteady-state displacements in which the standard pressure drop is measured external to the core between the inlet and outlet fluid streams. The dynamically measured capillary pressure properties – besides indicating strong, weak, intermediate, or mixed wettability – then can be used to derive relative permeabilities from the displacement data. Examples of the – technique for determining wettability are given for pure-fluids/Berea-sandstone and reservoir-fluids/preserved-reservoir-rock systems.
A Numerical Simulation Comparison of Five-Spot vs. Line Drive in Micellar/Polymer Flooding
Authors: Kazemi H. , MacMillan D. J. 
Published: December 2007

Abstract
The work presented in this paper was undertaken to study the effect of pattern configuration on oil recovery by the Maraflood™ oil-recovery process. The patterns studied are the five-spot and the 4× 1 line drive. These patterns are obtained by placing infill wells in an existing 10-acre (40 469-m2) waterflooded five-spot pattern to obtain the 2.5-acre (10 117-m2) patterns. The number of infill wells is the same for both the new five-spot and new line-drive configurations and is about three times the number of existing wells. Both patterns have been used successfully in field applications by Marathon before this study. For instance, a line-drive pattern was used in Project 119-R and a five-spot pattern was used in Project 219-R.
This work shows that the line drive produces more tertiary oil than the five-spot under otherwise identical reservoir conditions. Breakthrough times and oil rates for line-drive production wells are nearly the same. Meanwhile, five-spot production wells have vastly differing oil breakthrough times and oil rates. Both of the latter effects result from a nonuniform distribution of waterflood residual oil saturation in the field.
Our study also shows that if producing wells in each line-drive row are connected by a perfect vertical fracture and if the same is true of the injection wells, the line-drive efficiency will improve very little.