bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shaker Screen Characterization Through Image Analysis
Authors: Cutt A. R. 
Published: December 2007

Abstract
The labelling of shaker screens has been a problem. Existing mesh count designations do not adequately describe a shaker screen's potential separation performance. Consequently, it is difficult to make an informed decision when selecting shaker screens. The establishment of a standardized, performance-based designation system has been hindered largely by the time, expense and difficulty in deriving absolute screen separation efficiencies from full-scale laboratory testing.
This paper introduces a technique which overcomes this problem by relating the separation efficiency potential of a shaker screen to a volume-equivalent distribution of its hole sizes. Magnified, computer-enhanced visual images of screen apertures were measured using a PC-based image analyzer system. An equivalent volume distribution was then derived from this data to yield a curve corresponding to a grade efficiency or percent-separated function. These equivalent volume distributions were compared to experimental percent-separated values for square, oblong and layered mesh screens to confirm the viability of the image analysis technique.
Visualization and Numerical Studies of Bubble Growth during Pressure Depletion
Authors: Li X. , Yortsos Y. C. 
Published: December 2007

ABSTRACT
Bubble nucleation and bubble growth during pressure depletion in porous media is an important problem encountered in solution gas-drive. The problem was recently analyzed by Yortsos and Parlar (1989) who proposed a theoretical model valid at low decline rates. In this paper we continue their work using both experimental and numerical methods.A numerical pore network model is developed to simulate the process under various conditions. The model includes gas expansion, concentration gradients and finite size effects, previously neglected. Emphasis is placed on the determination of the critical gas saturation, Sgc, and on effects of the rate of pressure decline. Experiments similar to Yousfi et al. (1990) are also carried out in glass micromodels and Hele-Shaw cells. The nucleation of bubbles in various places and their subsequent growth are recorded. As previously predicted, bubble growth occurs from various nucleation sites, which are activated at different stages of the process. In the micromodel, bubbles grow as ramified clusters, which have the general features of a percolation process (e.g., similar to drainage). This is in contrast to Hele-Shaw cells, where growth of compact clusters is observed. Numerical simulation with the use of the pore network model gives results in good agreement with the experiments.
Large-Scale Averaging of Drainage at Local Capillary Control
Authors: Yortsos Y. C. , Satik C. , Salin D. , Bacri J. C. 
Published: December 2007

ABSTRACT
Present continuum models for large scale averaging rely on volume averaging and homogenization methods, typically under the premise of capillary control. However, such methods are intrinsically unable to provide the local saturation distribution, which is needed for the computation of effective flow properties. In this paper, paralleling porelevel approaches, a percolation method is proposed for the derivation of large scale properties in a drainage process at low flow rates. Percolation is applied to a macroscopically heterogeneous region with a random, uncorrelated permeability distribution. We show that at conditions of local capillary control, when a local description is possible, the large scale capillary pressure curve is a non-trivial average of the individual curves. Large scale capillary trapping is predicted and a corresponding large scale trapped saturation is calculated. Large scale phase premeabilities are also derived. It is found that capillary heterogeneity renders a system more strongly wet in a macroscopic sense.
Phase Behavior In Miscible Systems Of Solvent, Dry Gas And Oil
Authors: Meldau R.F. , Simon R. 
Published: December 2007

Introduction
In solvent injection projects, the injection fluid mixes with the reservoir oil being displaced. As the project proceeds, all the possible mixtures of reservoir oil and injection fluid from pure oil to pure injection fluid will occur. If all these mixtures are single phase at reservoir temperature and pressure, then the process is a miscible displacement, and high oil recovery can be obtained from the swept regions of the reservoir.
In most cases, the injection fluid is vaporized at reservoir conditions. Therefore, for a miscible displacement, it is necessary to have a composition transition from liquid reservoir oil to vaporized injection fluid without having two phases present at any one point in the reservoir.
A series of phase behavior experiments was conducted which showed the event which occur during the transition from pure reservoir oil to pure injection fluid. These events can be illustrated by Fig. 1.
Fig. 1 shows that the addition of injection fluid to reservoir oil produces a series of bubble point mixtures, then a critical mixture, and finally, a series of dew point mixtures. A bubble point mixture is defined as one which produces a gas as the second phase when the pressure is lowered into the two phase region. A dew point mixture produces a liquid as the second phase.
A Computerized Simulation Of A Heterogeneous Aquifer Storage Formation
Authors: Reed L.N. , Henderson J.H. , Dempsey J.R. , Coats K.H. 
Published: December 2007

Abstract
A multi-dimensional, two-phase numerical reservoir simulator has been used to model a completely heterogeneous aquifer formation in which natural gas is stored. The mathematical model accounts for the variables which affect aquifer storage performance, such as capillary pressure, gravity effects, aquifer strength, pressure, gravity effects, aquifer strength, reservoir heterogeneity and variable fluid properties. A procedure was utilized which properties. A procedure was utilized which permits automatic history matching of the field permits automatic history matching of the field pressure response to gas injection and pressure response to gas injection and withdrawal. Results are presented which indicate that a reliable reservoir description was obtained which allowed for a satisfactory match of historical pressure-response and will serve as a basis for future reservoir studies. The usefulness of the automatic matching procedure to determine reservoir parameters procedure to determine reservoir parameters based on matching of field response is emphasized.
Introduction
A company which utilizes underground gas storage must be confident of the dependability of the facility. It is imperative that the reservoir performance be accurately predicted to insure that the reservoir is capable of delivering the withdrawal rates as required. This guarantees the satisfaction of customer demands by incorporation of the storage field performance with the more easily determined mainline capacity. While all storage facilities have unique design and operational difficulties, perhaps the most difficult is gas storage in natural aquifers. This stems in part from the many variables which influence performance, the lack of performance data prior to development, and the performance data prior to development, and the introduction of a foreign hydrocarbon into a 100% water saturated zone. The engineers responsible for the development and operation of storage fields have historically been forced to make many simplifying assumptions in order to predict a field's performance, determine optimum development schemes, performance, determine optimum development schemes, etc. This situation is not unlike the problems faced by reservoir engineers concerned with the depletion of natural-occurring hydrocarbon reserves. The availability of high-speed digital computers and mathematical reservoir models offers a means to more rigorously study various gas storage problems incorporating the many variables which must be considered. This paper describes the approach we are taking to more accurately predict aquifer storage reservoir performance.
A New Approach to Modelling of Multicomponent Two-Phase EOR Processes With Interphase Mass Exchange
Authors: Brusilovsky A. I. , Zazovsky A. F. 
Published: December 2007

Abstract
A new approach to the analysis of multicomponent EOR processes with interphase mass exchange is proposed. It’s based on the splitting of mass exchange and flow problems corresponding to two-phase displacement in porous media. On the first stage phase and composition behavior of system inside the zone of mass exchange is investigated by means of simulation of various composition paths. All these paths, as it was found, are realized in a very strong narrowing of compositional space for every fixed compositions of displacing and displaced fluids.
This is very useful on the second stage when hydrodynamic calculations are worked out. Such an approach substantially reduces the expenses connected with repeated calculations of phase behavior for compositional models and it extends the application range for analytical methods.
The main features of new approach are illustrated for gas-drive EOR processes. The general form of cubic EOS is used for description of phase behavior in terms of real composition. Hydrodynamic calculations are fulfilled after the reduction of a real system to a three-component one. Generalization of common composition path simulation for immiscible oil displacement by gas agents is proposed. The results for methane and smoke gas injections in Tengiz and Surgut fields are presented.
Mechanisms of Miscible Oil Recovery: Effects of Pore-Level Fluid Distribution
Authors: Stern D. 
Published: December 2007

Abstract
A series of tertiary multiple-contact miscible CO2 corefloods have been carried out to study effects of flow rate, core length, oil viscosity, wettability, WAG ratio, and initial water saturation on displacement mechanisms. The goal of these experiments was to identify important recovery mechanisms that influence performance of reservoir-condition, multiple-contact miscible floods.
In these experiments, a bank of miscibly-displaced oil is produced first, followed by oil that is initially lighter than the original oil, and becomes increasingly heavy as the flood progresses. The implication is that some oil is initially bypassed and later recovered by extraction.
The amount of bypassing is not sensitive to flow rate or core length, but increases as the solvent/oil viscosity ratio decreases. Based on these results, it is concluded that pore-level effects such as capillarity-induced bypassing and dispersion are major bypassing mechanisms. Microvisualization experiments, in which fluids are hardened in-place, provide direct confirmation that pore-level bypassing takes place.
Viscous fingering (macroscopic bypassing) may also take place, but it is not thought to be the dominant bypassing mechanism under the conditions of this study.
Wettability also has a significant effect on coreflood performance, particularly at high WAG ratios. High WAG ratios result in less oil recovery by extraction. In water-wet rock, this is a large effect, with almost no extraction at high WAG ratios. In mixed-wet rock, however, the effect of WAG ratio is much smaller, and significant quantities of oil are recovered by extraction regardless of WAG ratio. This is likely the result of wall-coating oil films in the mixed-wet rock, which improve contact between oil and solvent.
Analytic Solutions for Elliptical Finite-Conductivity Fractures
Authors: Riley M. F. , Brigham W. E. , Home R. N. 
Published: December 2007

ABSTRACT
The purpose of this study is to develop exact analytic solutions for the pressure response of a finite conductivity fracture. This model should be able to verify the existence of various flow regimes found in earlier studies. It is hoped that this solution could be modified to give simplified expressions for well pressures for all times and all fracture conductivity ranges.
The present work poses and solves the problem of a vertical finite conductivity fracture of elliptical cross-section. The flow within the fracture is assumed to be incompressible and the reservoir is assumed to be infinite. The elliptical fracture geometry was chosen to facilitate the expression of fracture and reservoir pressures as eigenfunction expansions.
The solution is obtained by expressing the reservoir pressure as a series of Mathieu functions, and the fracture pressure as a series of cosines. The coefficients in these series satisfy an infinite set of linear relations, termed Fredholm sum equations. Exact solutions to these sum equations are obtained in forms which resemble continued fractions of summations, or equivalently, which require iteration of rational forms. A great deal of effort has been expended to speed the calculation of the solutions, however, only partial success has been achieved.
The solutions become increasingly difficult to compute as time decreases. So, approximate solutions for well pressures are given for extremely low values of time. These solutions indicate that behavior of an elliptical fracture is essentially the same as that of a rectangular fracture. Indeed, the well pressures calculated in this work are quite close to those for a rectangular fracture. Generally applicable simplified well solutions have not been found.
Electrical and Petrophysical Properties of Carbonate Rocks
Authors: Wang Zhijing , Hirsche W. K. , Sedgwick G. E. 
Published: December 2007

ABSTRACT
Electrical and other petrophysical properties were measured in the laboratory versus pressure in 54 carbonate core samples from 11 oil-producing reservoirs. The measured electrical and petrophysical properties include formation factor F, cementation exponent m, and saturation exponent n, porosity φ, permeability K, grain density ps, capillary pressure Pc, residual (irreducible) water saturation Swr, and sonic velocities. In the measured cores, systematic relationships exist between formation factor and porosity, permeability and porosity, permeability and residual water saturation, saturation exponent and residual water saturation, and formation factor and sonic velocities, although the data are significantly scattered. The formation factors were best-fit to Archie’s equation so that the coefficient a and cementation exponent m were obtained. The empirical equations allow for calculation of porosity from formation factor, permeability from porosity and residual water saturation, and saturation exponent from residual water saturation, or vise versa.
Reservoir Heterogeneity at Seventy-Six West Field, Texas: An Opportunity for Increased Oil Recovery From Barrier/Strandplain Reservoirs of the Jackson-Yegua Trend by Geologically Targeted Infill Drilling
Authors: Hamilton D. S. 
Published: December 2007

Abstract
Seventy-Six West field, in northwest Duval County, South Texas, produces from the uppermost Jackson Group at depths of 1300 to 1400 ft [396 to 426 m]. Reservoir geometry is highly complex, consisting of strike-oriented beach ridge, channel, and sand-poor lagoonal facies, which are modified by dip-oriented tidal-inlet fill and washover sands. Production trends mirror the beach ridge and channel facies but are also influenced by dip-oriented facies and by small normal faults. The reservoir is heterogeneous and has an estimated 6 MMBbl [9.5 × 105 stock-tank m3] of remaining mobile oil trapped in untapped compartments and poorly swept zones. Results of detailed reservoir characterization identify these compartments and provide targets for infill drilling. Results at Seventy-Six West field are applicable to nearly 300 similar South Texas fields.
Application of the Pulse Decay Technique
Authors: Gilicz A. 
Published: December 2007

ABSTRACT
In recent years the pulse decay technique became a frequent tool for the fast and convenient measurement of permeability and porosity of mostly tight rocks. The method is superior to conventional steady state methods as it is much faster and easier to perform. So far it was applied to linear cores (plugs) only. In the last years radial models appeared widely as they show some advantages over linear models, so the need emerged to apply the method for radial cores. Experimental apparatus and mathematical models have been developed to solve the problem. The current paper describes experimental set-up, analytical solutions of the governing equation and applications of them to performed measurements.
A Model for the Simultaneous Generation of Core-Controlled Stochastic Absolute and Relative Permeability Fields
Authors: Tjølsen C. B. , Damsleth E. 
Published: December 2007

ABSTRACT
During the last few years, a two-stage stochastic model for 3-D modelling of reservoir architecure and absolute permeability1 has been developed and utilized in field development studies. The scope of this paper is to present a new, important extension of this model: The possibility of generating relative permeability curves with stochastic spatial variation. Absolute permeability can be measured on cores as well as in analogue outcrops, using a field minipermeameter. Relative permeabilities, however, are in general time consuming and expensive to measure. For this reason, they are usually measured on a very limited number of core samples. Relationships or interdependendencies among petrophysical variables are required as input to the stochastic model. Based on a unique set of core data containing relative permeability curves measured on 85 core plugs from one single well in the North Sea, correlations between relative permeability curves (represented by endpoints and Corey-exponents), absolute permeability and depositional environment have been developed2. Utilizing these correlations, the paper demonstrates a co-kriging procedure for simultaneously generating absolute and relative permeability fields.
An example based on data from a North Sea reservoir is given to illustrate the model and its application. To evaluate the effect of different relative permeability curves in each grid cell, flow simulations were performed. The same grid was used for the flow simulations as for the stochastic realizations, to avoid the problem of homogenization of the relative permeability curves. The results indicate that in the cases studied, the introduction of stochastic variation in the relative permeability curves has no significant effect on the shape of the production profile, when compared to the case with a constant relative permeability curve.
Stochastic Heterogeneity Models of Thin, Laterally Continuous North Sea Sandstones and their Influence on Simulated Reservoir Performance
Authors: Aasen J. O. , Høye T. H. , MacDonald A. C. , Grindheim A. O. , Jacobsen T. , Storvik G. , Holden L. M. 
Published: December 2007

Abstract
The paper presents an application of a stochastic reservoir description simulator to the modelling of two sections of a coastal-deltaic reservoir, the Tarbert Formation in the Gullfaks Field. The description simulator, called DESIRÈ, models reservoir architecture by an ordered sequence of widespread facies types on which are superimposed bodies or infinitely thin barriers. Petrophysical variables are simulated conditionally on architecture. The reservoirs display features of a coastline progradation and a sandflat sequence, interspersed with bodies of tidal origin and calcite cemented zones. Contoured- and flow unit models have been constructed for the reservoirs, and sets of realisations from the models have been simulated. Production simulations of water injection have been performed on all realisations. The production results show that with the data available for analysis, significant uncertainty remains in predicted behaviour irrespective of the comparatively simple structure of the reservoirs under study.
Fractional Dimension Analysis of Constant-Pressure Well Tests
Authors: Doe T. W. 
Published: December 2007

ABSTRACT
This paper presents a discussion of spatial dimension and applies a generalized dimension approach to interpreting constant-pressure well tests. The spatial dimension of a well test is determined by the power by which either the surface area or reservoir properties change with distance from the source. The dimension equals the power of variation plus one. Fractional dimensions arise when the power of variation is not an integer. Fractional dimension behavior may indicate either fractal reservoir geometries or non-fractal geometries which are not space-filling. The dimension of a well test is distinctive in logarithmic plots of flow rate versus time. For dimensions between 1 and 2, the flow rate declines along a straight line with a slope equal to n/2-1 where n is the dimension. Determination of reservoir properties is complicated by uncertainties in the space-filling proportion of the reservoir, conducting surface areas of the reservoir, and the effective radius of the well.
Numerical Construction and Flow Simulation in Networks of Fractures Using Fractal Geometry
Authors: Acuna J. A. , Yortsos Y. C. 
Published: December 2007

ABSTRACT
Present models for the representation of naturally fractured systems rely on the double-porosity Warren-Root model or on random arrays of fractures. However, field observation in outcrops has demonstrated the existence of multiple length scales in many naturally fractured media. The existing models fail to capture this important fractal property. In this paper, we use concepts from the theory of fragmentation and from fractal geometry for the numerical construction of networks of fractures that have fractal characteristics. The method is based mainly on the work of Barnsley [1] and allows for great flexibility in the development of patterns. Numerical techniques are developed for the simulation of unsteady single phase flow in such networks. It is found that the pressure transient response of finite fractals behaves according to the analytical predictions of Chang and Yortsos [6], provided that there exists a power law in the mass-radius relationship around the test well location. Otherwise, finite size effects become significant and interfere severely with the identification of the underlying fractal structure.
Quantifying Horizontal Well Logs in Naturally Fractured Reservoirs—I
Authors: Svor T. R. , Meehan D. N. 
Published: December 2007

ABSTRACT
Horizontal wells have been applied in many types of reservoir conditions with a variety of applications. The most successful of these has been exploiting the very large horizontal permeability anisotropics associated with naturally fractured reservoirs. Log analysis has always been difficult in naturally fractured reservoirs; very little has been published regarding horizontal well logs. This paper summarizes Union Pacific Resources (UPRC) experience logging dozens of horizontal wells in several different naturally fractured reservoirs, summarizes the improved information resulting from this experience, contrasts various well logs applicable in such areas, and describes a method for categorizing fracture apertures used to quantify the total horizontal well fracture index CRH).
UPRC has logged dozens of horizontal wells in the Bakken, Niobrara, Austin Chalk, Buda, Georgetown, and Second White Specks formations with oriented microresistivity devices (FMS), borehole acoustic televiewers (BATV), four and six arm dipmeters, and sonic logs. Formation evaluation objectives have included determining the depth of most intensely fractured intervals, identifying and quantifying number and aperture of fractures encountered, locating faults and bed boundaries, determining fracture azimuths, and for use in subsequent production operations. The use of vertical and 45 degree ‘pilot’ holes is compared, showing significantly superior results using a 45 degree well to detect the fractured intervals. The applicability of the various tools are described with examples of each being presented. The UNIX-workstation based methodology for approximate quantification of fracture azimuths into aperture-based categories is described, along with the procedure to determine the RFI. A horizontal well log presentation is discussed that illustrates difficulties in mud log interpretation.