bluuebunny/crossref_metadata_2025_split huggingface dataset:
Vertical Permeability From Limited Entry Flow Tests in Thick Formations
Authors: Raghavan R. , Clark K.K. 
Published: December 2007

Abstract
This paper examines the applicability of the spherical flow equations to a well producing from a limited section of a thick anisotropic formation. Though the method of analysis was suggested by Moran and Finklea several years ago, the applicability of these equations is yet to be demonstrated. Methods of determining the horizontal and vertical permeability of the formation from drawdown and buildup data are described. The effect of producing time on the determination of these parameters is discussed. Time estimates are provided parameters is discussed. Time estimates are provided to obtain the proper straight line.

Introduction
Transient pressure analysis of early time data of limited entry tests precludes the use of conventional semilog techniques. This is principally due to the nonradial flow regime developed in the vicinity of the wellbore at early times Moran and Finklea suggested that early-time pressure behavior from such tests can be adequately described by assuming the limited entry section to be a spherical source rather than a cylindrical source, as in the case of a well completely penetrating the formation of interest. More recently Culham has examined the applicability of the spherical flow equations to well tests wherein the producing interval is a small fraction of the total pay thickness. He developed guidelines for analyzing pay thickness. He developed guidelines for analyzing the pressure buildup data based on the assumption of spherical flow. Culham was principally interested in homogeneous thick formations. The primary objective of this paper, however, is to demonstrate that information may be obtained regarding reservoir heterogeneity specifically permeability anisotropy. This type of information is crucial to predict the performance of zones of interest under a variety of performance of zones of interest under a variety of conditions such as the presence of barriers, and the movement of fluid interfaces.

MATHEMATICAL MODEL
A cross-section of the idealized limited entry model is shown in Fig. 1. The following assumptions are made:The reservoir is horizontal with uniform thickness, h, porosity, phi, and infinite radial extent. It has anisotropic radial and vertical permeabilities, kr and kz, respectively. The well, which may or may not fully penetrate the formation, has an infinitely small radius, rw.A single-phase, slightly compressible liquid flows from the reservoir into the open section at a constant rate, q.The single, horizontal, open section has a radius rw, thickness hf, and is assumed to be located near the center of the producing interval. The midpoint of the open interval is located at a distance zf from the bottom of the pay. Fluid is withdrawn uniformly along the section open to flow.There is no flow across the upper and lower boundaries of the reservoir; and the pressure remains unchanged and equal to the initial pressure as radial distance approaches infinity.
One point regarding the model discussed above requires clarification.
SPEJ
P. 65
Physsicochemical Aspects of Microemulsion Flooding
Authors: Healy Robert N. , Reed Ronald L. 
Published: December 2007

Abstract
Whenever water, an oil, and a surfactant equilibrate at concentrations of surfactant in excess of critical micelle concentrations, one or more microemulsions form.. In view of this, all surfactant flooding processes may involve microemulsions in situ. Ternary diagrams have been constructed for three specific microemulsion systems showing The effects of salinity and cosurfactant on phase behavior, viscosity, resistivity, optical birefringence, and interfacial tension. Using these data, micellar structure maps were prepared for the single-phase region. In this connection, Winsor's concept of intermicellar equilibrium was found consistent with microemulsion systems of interest for tertiary oil recovery. Experimental techniques are described for minimizing the extent of the multiphase region and measuring the low interfacial tensions that obtain there.

Introduction

GENERAL CONSIDERATIONS
It is sometimes difficult to sort out the multiplicity of terminology concerning various kinds of micellar solutions and the structural states in which they exist. For example, Schulman introduced the term "micro emulsion." Winsor objects on the grounds that all emulsions are unstable and a microemulsion must be some kind of an emulsion. Tosch et al. use the phrase "micelle-containing solutions," whereas Shinoda and Kunieda prefer "swollen micellar solution." Nevertheless, the term microemulsion is convenient, is in common use, and it is only necessary to understand precisely what is meant by the term. In this paper a microemulsion is defined to be a stable, translucent micellar-solution of oil, water that may contain electrolytes, and one or more amphiphilic compounds (surfactants, alcohols, etc.). It should be noted that according to this definition a microemulsion is not an emulsion. A microemulsion may have distinct internal and external phases, but in many cases there is no identifiable external phase. phase. Since a microemulsion has at least three components -- oil, water, and surfactant - the compositional state of the system must be specified with at least three numbers. It is therefore convenient and instructive to employ a ternary representation as shown in Fig. 1. The simple situation will involve three pure components, and the multiphase region will be bounded by a continuous binodal curve. Everywhere above the binodal curve a single phase exists that undergoes transitions among various structural states as the compositional point moves about the diagram. These transitions may be gradual, reflecting an equilibrium in which there is significant coexistence of different micellar configurations, as proposed by Winsor. proposed by Winsor. In the multiphase region, the most simple, three-component system involves only two phases throughout; one is oil-external and the other water-external.
SPEJ
P. 491
A Material-Balance Technique for Undersaturated, Partially Water-Driven Reservoirs
Authors: Barry Richard A. 
Published: December 2007

Abstract
A modification of the standard material-balance equation for undersaturated reservoirs is presented. The effect of water influx is accounted for by the term, which is the ratio of the aquifer to reservoir pore volumes.For an approximately circular reservoir, values of, may be obtained quite easily by reiteration from the internal-cylinder solution of the diffusivity equation. The technique has been applied to a Colombian field, with acceptable results.

Introduction
Weak water drives that might have a negligible effect below the bubble point may exert a very appreciable influence above the bubble point. Under these conditions, use of the standard material-balance equation (as presented by Hawkins, and by Hobson and Mrosovsky) may lead to considerable error. This paper presents a modification to the standard equation; a field example indicates that the technique yields acceptable results. The method is quite straight-forward, its solution requiring only a desk calculator and a book of six-figure tables.

Derivation of the Modified Equation
Let the reservoir pore volume be Vpo. At any time t, let the effective pore volume of the aquifer that has been influenced by the pressure drop in the reservoir be Vpa.At a pressure drop p, the total pore space will be reduced to . The initial water volume of the reservoir is increased fromto . Hence,=.
Originally,
and
Hence,
Sorting into a more conventional form,
.....(1)
Evaluation of Ritchie and Sakakura have presented a solution to the diffusivity equation for a uniform system of infinite extent, bounded internally by a cylinder of radius rw. It seems likely that the majority of field engineers may be unable to obtain copies of Ref. 3. However, Mortada offers quite a thorough discussion of this solution and its modification for nonuniform aquifers.In oilfield units (and ignoring third- and higher-order terms), the solution reduces to
......................(2)
and
JPT
P. 391^
Solutions to the Diffusion Equation for a Region Bounded By a Circular Discontinuity
Authors: Larkin Bert K. 
Published: December 2007

Abstract
Solutions to the diffusion equation for a line source located anywhere in a region bounded by a circular discontinuity are presented. Such solutions follow automatically from the Green's function presented by Jaeger. Petroleum industry applications of this problem would include transient compressible fluid flow in porous media bounded by a discontinuity. Since several recent papers have treated the subject in less general form, it would appear that many workers in this area of the petroleum industry are not aware of Jaeger's work.

STATEMENT OF THE PROBLEM
In several treatments of the transient flow of compressible fluids in porous media it was convenient to consider a region to be bounded by a circular discontinuity. In such a region (Fig. 1), the properties in Region 1, r less than a, are constant but different from the properties in Region 2, r greater than a. Hurst, using the Laplace transform, obtained solutions for a line source located in the center of such a porous medium. The purpose of this work is to point out that a much earlier paper by Jaeger presents the solution for a line source located anywhere inside the discontinuity. The assumption is made that a line source may be used to approximate a well. In the following material it is convenient to use the terms source and well as being equivalent; however, the reader should remember the distinction in applications.

SOLUTIONS
Jaeger presented the Green's function for a line source, or well, in the composite region shown in Fig. 1. In the most general form, the solution for a system of j wells in Region 1, each producing at a time varying rate, qi(t), is
..................(1)
The Green's function vi corresponds to the solution for an instantaneous line source at position ri, 0i (Fig. 1). Integration in time, previously shown, gives the contribution from a single well, and summing over all j wells in the reservoir gives the total solution. Equations defining v are presented by Jaeger as well as an outline of the method of solution.From Jaeger's work it can be shown that
....(2)
for r less than a, ri less than a
(3)
SPEJ
P. 113^
An Approximate Infinite Conductivity Solution for a Partially Penetrating Line-Source Well
Authors: Gringarten Alain C. , Ramey Henry J. 
Published: December 2007

Abstract
A review of previous studies of transient flow to partially penetrating wells was made. All analytical studies involved the assumption of a constant flux along the open interval. This analytical study is a new solution that closely approximates an infinite-conductivity line source (constant pressure along the producing interval).

Introduction
The problem of fluid flow to wells with partial penetration or restricted entry has received much penetration or restricted entry has received much attention in the last 15 years, both in ground-water hydrologyl and in petroleum engineering. A number of steady-state and unsteady-state solutions have appeared in the literature, and methods for analyzing pressure data have been proposed by several authors. pressure data have been proposed by several authors. Some of these methods have been aimed at determining the reservoir vertical permeability. Although many different techniques have been used for solving the partial penetration problem (namely, the point-source solution, Fourier and Laplace transforms, Hankel and Laplace transforms, Green's functions, finite differences, finite elements, an electric analyzer, a thermal model, and a fluid flow model), the analytical expressions and the numerical results obtained for reservoir pressures by the different methods were essentially identical. There were some differences, however, between the values of wellbore pressures computed from numerical models and those obtained from analytical solutions. Analytical solutions were derived by making the assumption of uniform fluid withdrawal along the portion of the wellbore open to flow. With the nomenclature of Fig. 1, this is written as(1)
It appears more realistic to expect the producing pressure to be independent of n Producing pressures pressure to be independent of n Producing pressures would differ only by virtue of the potential head of flowing fluid and friction over the producing interval, assuming the wellbore is open.
SPEJ
P. 140
Field Trial of Caustic Flooding Process
Authors: Graue D.J. , Johnson C.E. 
Published: December 2007

A field trial of caustic flooding is reported for a reservoir containing a 20 degrees API oil. Field data showed the process to behave qualitatively as it does in laboratory core floods. Incremental oil over waterflooding for the field trial was estimated at 350,000 STB. The caustic flood resulted in no injection or producing problems. problems. Introduction
In Oct. 1966 an experimental secondary recovery project was begun in a limited portion of the existing project was begun in a limited portion of the existing second and third zones waterflood in the Whittier oil field in Whittier, Calif. The major feature of the oil recovery scheme was a caustic flood conducted in the area shown in Fig. 1 that was in the center of the field. The caustic flooding process was used because laboratory tests had indicated that a considerable increase in oil recovery would result over plain waterflooding in this field. Screening tests on many crude oils for susceptibility to caustic flooding had earlier shown that the Whittier second- and third-zone crude reacted favorably with caustic to give extremely low interfacial tensions. It was believed that these low interfacial tensions, shown in Fig. 2, would result in much improved volumetric sweep efficiencies through a mechanism of in-situ emulsification.

Reservoir Description Formation
A typical well log of the section including the second and third zones is shown in Fig. 3. The top of the second zone occurs at an average subsea depth of 1,500 ft and the top of the third zone is at 2,100 ft. The net oil sand in the two zones averages about 37 and 100 ft, respectively, with porosity of about 30 percent in both zones and arithmetic air permeabilities percent in both zones and arithmetic air permeabilities of 495 and 320 md, respectively. Both zones dip sharply to the south at an angle of 25 degrees to 45 degrees. A fault runs roughly east and west across the middle of the field and forms a natural barrier for the pilot area. pilot area. Reservoir Fluid
The gravity of the oil averaged 20 degrees API and the viscosity at reservoir conditions of 365 psi and 120 degrees F was about 40 cp.

Wells
The well spacing in the 63-acre project area varied between 1 and 2 acres per well. The project began with 45 producers and four injectors in the two zones. Later problems required the conversion of one producer to injection. All of the producers in the project area were completed in both sands except for the three wells noted in Fig. 1. The four initial injectors Wells 48, 75, 157, and 135initially injected controlled amounts into each of the two test zones. The well problems mentioned earlier required shutting off Well 48 injection into the second zone, and injection from Wells 75 and 157 into the third zone. To replace this lost injection, Well 178 was converted to injection in the third zone.

Reservoir Performance During Waterflood
Water injection into the project area began in early 1964.
P. 1353
A Variable-Rate Procedure for Appraising Wellbore Damage in Waterflood Input Wells
Authors: Johnson C.R. , Greenkorn R.A. , Widner G.W. 
Published: December 2007

Abstract
This paper describes a short, simple well-testing procedure evolved from unsteady-state concepts to appraise wellbore damage in water-input wells. Input rates are changed at specific intervals over a 30-minute period and the wellhead pressure recorded at the end of each interval. From these data, the pressure drop due to the "skin" can he computed. This pressure drop in terms of psi/B/D of input rate is referred to as the "skin factor". Two of these variable-rate tests are required to determine change of wellbore damage and to evaluate well-treatment techniques.There are several advantages to the variable-rate procedure. The necessary data can be obtained with wellhead gauges and meters. There is little interference with normal operations. The short testing period eliminates many interpretative difficulties that come from interference from adjacent wells. The shut-in period required for standard tests before the plot of pressure vs log of time attains a straight line is often 12 hours or more. Such a time period is inconvenient, especially when a well must be tested repeatedly to evaluate change in wellbore characteristics.This variable-rate procedure has been successfully applied to water-input wells in three fields. For some of the wells, skin factors were calculated from both the standard and the variable-rate tests. These results show good agreement.

THEORY OF THE VARIABLE-RATE PROCEDURE
In many waterflood input wells, the pressure in the wellbore differs from the pressure in the reservoir immediately adjacent to the well because of the restriction of flow through the skin of the well. If the true pressure of the reservoir at the well, pt, is that pressure which would exist in the well if no skin were present, and pt' is the actual pressure as measured in the well, this difference, pt'-pt, is the skin effect.Fig. 1 shows the change in skin effect with change in flow rate. As the flow is reduced, the skin effect pt'-pt is reduced by an amount equal to the change in wellbore pressure minus the change in reservoir pressure.The equation of pressure change without skin using the point-source solution of the diffusivity equation is (after van Everdingen)
........................................(1)
where q = flow rate, B/D, k = permeability, md, h = thickness, ft, = porosity, psi,= viscosity, cp, c = compressibility, vol/vol/psi, rw = well radius, ft, and t = time, minutes.
With skin factor S, it may be written
..............(2)
JPT
P. 85^
Log Interpretation Problem in Low Resistivity Sands
Authors: Blum Harold A. , Martin John L. 
Published: December 2007

Abstract
All recent investigations have attributed low electric log resistivities in producing formations to a conductive ion layer associated with clay material present in the sands. In this study another mechanism is proposed. It is believed that connate water saturation variations (which may or may not be associated with shale contact) also contribute to low resistivities. In addition to the mechanistic studies, evaluation of various recently proposed interpretation methods have been made. Of these, the Poupon, Loy, and Tixier and de Witte methods seem best.

Statement of Problem
Low resistivity sands are often encountered which turn out to be commercial hydrocarbon zones but appear from electric log data to be water bearing. Adequate methods of recognizing these cases are needed. Industry-wide interest in this problem is evidenced by the number of papers published in recent years. It seemed that several zones in the Mustang Island field (Nueces County, Tex.) were affected by the shaly sand problem. This was evidenced by:low hydrocarbon saturation calculations from logs and measured formation factor data in producing zones,changes in apparent measured formation factors with changes in water resistivity, andcore descriptions which indicated the presence of shaly "streaks" or "spots."
A section of a typical log is shown in Fig. 1. All sands on this log are hydrocarbon zones.

Scope of Investigation
The Mustang Island field, Nueces County, Tex., has been chosen for the study of the shaly sand problem because the oil-water contacts are well established for most of the sands and some core data were available for study. This problem has been approached by both empirical and experimental methods. The empirical portion of this study is a comparison of calculated hydrocarbon saturations from logs by various methods with expected or known production (oil, gas, or water).
Effects of Compressibility and Solution Gas on The Gas Drive Mechanism for Linear and Radial Systems
Authors: Carlson F.M. , Land C.S. 
Published: December 2007

A numerical model was constructed to investigate the effects of compressibility, and solution on the immiscible gas drive mechanism. Based on the results of this model, these effects can be predicted using a modification of the Buckley-Leverett and Kern solutions.

Introduction
A theory describing linear displacement of one fluid by another in porous media was developed in 1941 by Buckley and Leverett. The validity of two of the simplifying assumptions made in their development would seem to depend on the type of fluid used as the displacing phase. The first assumption is that the density of each phase remains constant throughout the reservoir. This supposition is realistic when the oil is displaced by water owing to the relative incompressibility of the two phases. However, when the oil is displaced by gas, this assumption becomes somewhat incredible owing to the fact that the gas is extremely compressible. The other assumption, peculiar only to the displacement of oil by gas, is the constancy of the solution gas during the period of injection. This conjecture would seem unreasonable, inasmuch as when gas is injected at a pressure greater than the saturation pressure of the oil, an pressure greater than the saturation pressure of the oil, an increase in the amount of solution gas per volume of oil undoubtedly occurs.
Recognizing these limitations of the Buckley-Leverett theory, Kern presented a modification that takes into account a change in solution gas when gas is injected into an undersaturated reservoir. In this derivation, gas is assumed to be compressed to the volume it would occupy at the injection pressure, and it is postulated that gas remains in this compressed state until breakthrough of the gas. The saturation pressure of the oil is considered to change from the initial bubble-point pressure to a new value equivalent to the injection pressure. Pirson offered a graphical technique for solving Kern's equations. Using this method, saturation at the front and average saturation behind the front can be found in a manner similar to that proposed by Welge.
Consequently, the object of this study is to demonstrate with the aid of a numerical model the effect of compressibility and changing fluid properties on the gas displacement mechanism. Complete details of this study can be found elsewhere. A digital computer is used to solve the finite-difference representations of the partial differential equations of motion for the simultaneous flow of oil and gas through porous media. Results from the solutions of Buckley-Leverett, Kern, and the numerical model are contrasted. Suggestions are made as to the reasons for the differences in the three solutions. A variation to the Kern solution for both linear and radial systems is presented for estimating recoveries at breakthrough when injection, production, and initial bubble-point pressures are known.
JPT
P. 1079