bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of the Centrifugal Model to the Study of Reservoir Behavior
Authors: Goodwin R.J. , Massey D.G. , Crawford Paul B. 
Published: December 2007

Abstract
A centrifugal reservoir model has been constructed for studying solution gas-drive phenomena. The model has been used to study the effect of oil properties, well location and producing rate on the recovery of oil from a solution-gas-drive reservoir. Gravity segregation effects were minimized by the slow rotation of the model about a horizontal axis. The studies were conducted on a synthetic porous media having a permeability of less than 10 md; the bubble point of the crude oil ranged from a few hundred to over 2,000 psi; connate water was present.
It was found that the crude oil properties had a very large effect on the total oil recovery. The effect of well spacing and rate of production is presented. It was found that for the conditions of the test the well spacing and production rate may have an effect on the oil recovery depending on the reservoir system and producing technique.

Introduction
In 1952 the Texas Petroleum Research Committee initiated a research project to study criteria for determining the most efficient rate of producing an oil reservoir. A large number of articles bearing directly on this subject have appeared in the literature. Three recent reports on this subject have included literature reviews so a review is not repeated here. Field data have been used, model studies made, and certain mathematical techniques have been used to estimate the effect of reservoir rock and fluid properties, rate of production and well spacing on solution gas-drive performance.
Following the review of the literature it was decided that a laboratory model would be built in which one could simulate a solution gas-drive reservoir so that one could determine experimentally the effect of production rate, well spacing, and fluid and reservoir properties on oil recoveries.
Small parts of reservoirs have been built in various shapes and sizes to represent reservoir conditions; however, gravitational effects in the actual reservoir and the part of a reservoir used in the laboratory may not be the same. The overall effects of gravity in either an actual reservoir or a part of a reservoir used in the laboratory are not well defined.
A Systematic Approach to the Relative Permeability Problem in Reservoir Simulation
Authors: Molina Nelson N. 
Published: December 2007

ABSTRACT
Direct experimental determination of three-phase relative permeability data is extremely difficult. For this reason, numerical models describing multiphase flow in petroleum reservoirs determine three-phase relative permeability functions using two sets of the more easily measured two-phase data, i.e., water-oil and gas-oil displacement systems. However, because of the wide range of scattering of the laboratory-measured two-phase relative permeability data, it is usually very difficult to determine a representative average function whether by reservoir layers (different lithologies) or reservoir regions (several facies or reservoir units). It follows that our greatest need today in the area of reservoir simulation is a quick, relatively inexpensive procedure to match reservoir performance data based on adjustments of representative relative permeability functions assigned on a permeability distribution basis. A systematic approach to this problem is discussed in this study.
Fluid saturation and relative permeability values corresponding to the beginning, intersection, and end points of the displacement process were correlated as a logarithmic function of air permeability to determine initial saturation functions for each rock type (regions with identical capillary pressure and relative permeability properties). This procedure proved to be useful for water-oil and gas-oil systems of carbonate and sandstone reservoirs. The so determined saturation functions were curve fitted using exponential equations as starting points during the history match phase. Subsequently, the shapes of the relative permeability curves were adjusted by changing the exponents of the fitting equations in order to match WOR and/or GOR production history. This procedure assumes no mass diffusion and isothermal reservoir conditions. This approach has been successfully applied to match reservoir production history of different oil fields of the world, even when adverse mobility ratio conditions were present in stratified reservoirs.
The following are included: typical fluid saturation and relative permeability correlations as a logarithmic function of air permeability, relative permeability fitting equations, and applications to match the observed performance of selected case histories.
Compositional Variations within a Hydrocarbon Column due to Gravity
Authors: Schulte A. M. 
Published: December 2007

ABSTRACT
Gravity forces may generate and stabilise variations in composition along the hydrocarbon column in thick reservoirs. From the condition of thermodynamic equilibrium in a hydrocarbon column in the field of gravity one may determine with an equation of state the variations in composition with depth. The developed calculational procedure uses the Soave and Peng-Robinson equation of state. Results are shown for various hydrocarbon systems. Aromatics content, overall pressure and the introduction of binary interaction coefficients in the equation of state are seen to have strong influence on the predictions of gravity segregation. Observed compositional variations and corresponding variations in bubble points/dew points as well as the occurrence of natural miscibility between cap gas and reservoir oil can be explained.
Adsorption and Interfacial Tension Dynamics of Surfactants in Porous Media
Authors: Ramirez W. Fred , Friedman Francois , Denoyelle Ludovic C. , Shuler Pat J. 
Published: December 2007

ABSTRACT
The objective of this work is an understanding of the dynamic mechanisms associated with the adsorption of surfactants on porous media and the dynamics associated with the lowering of the interfacial tension between oil and a surfactant solution.
Most studies on surfactant adsorption have assumed that the adsorption mechanism occurs rapidly as compared with convection and dispersion. Trogus et al. (1977) have proposed a kinetic model which at equilibrium yields the Langmuir isotherm. Results of using this model have shown that the kinetic rate constant increases with an increase in phase velocity. An explanation for this variation is to postulate separate mass transfer and kinetic adsorption mechanisms. A new model is proposed and tested which consists of the solute moving to the rock-fluid interface by a mass transfer mechanism and then adsorbing to the rock via a kinetic mechanism. The mass transfer rate constant has been evaluated and correlated as a function of phase velocity. The correlation obtained for Berea sandstone and Triton X-100 (non-ionic) surfactant is in good agreement with existing mass transfer correlations for packed-bed reactors, indicating the validity of our mass transfer model for describing the transport of surfactant through porous media.
Using a spinning drop tensiometer, the dynamic response of the interfacial tension between n-decane, and a brine solution of Texas No. 1 surfactant or TRS 10–80 surfactant was obtained. A kinetic adsorption/ desorption rate model for the dynamic behavior was developed. At high surfactant concentrations the normal interfacial tension decrease stops abruptly at a specific plateau value. This plateau breakpoint seems to be due to an abrupt phase change at the interface which prevents the continued adsorption of surfactant monomer molecules. The breakpoint disappears at low surfactant concentrations allowing a normal equilibrium condition to be reached. An increase in surfactant concentration increases the interfacial tension dynamic response rate. Close to the optimal salinity the dynamic behavior is slow with Texas No. 1 and fast with TRS 10–80. We have linked these observations to the Van der Waals energy of desorption and the Gouy surface potential of the double layer.
Determination of Fissure Volume and Block Size in Fractured Reservoirs by Type-Curve Analysis
Authors: Bourdet Dominique , Gringarten Alain C. 
Published: December 2007

ABSTRACT
A new type-curve is presented for analyzing wells with wellbore storage and skin in double porosity systems. This type-curve applies to damaged, acidized, and fractured wells in fissured reservoirs. In addition to the usual well and reservoir parameters (permeability, skin, wellbore storage constant and length of the fracture intersecting the well), analysis yields characteristic parameters that can provide quantitative information on the volume of fissures and the size of porous blocks in the reservoir. These, in classical methods, could only be obtained if semilog radial flow were present at both early and late times, (thus yielding two characteristic parallel semi-log straight lines on a Horner plot), a condition that is seldom satisfied in practice.
The analysis method presented in the paper is illustrated with actual field examples from several different fissured reservoirs.
Techniques for Fully Implicit Reservoir Simulation
Authors: Au Anthony D. K. , Behie Alda , Rubin Barry , Vinsorne Kaz 
Published: December 2007

ABSTRACT
This paper summarizes the methods that have been used to develop fully implicit and highly implicit reservoir simulators.
The techniques developed emphasize simplicity and clarity. The governing equations, written in fully implicit form are treated as functions. These coupled nonlinear functions are solved by Newtonian iteration, the derivatives of the Jacobian matrix being evaluated numerically. A procedure is described for the efficient evaluation of the Jacobian.
A technique is presented for avoiding variable substitution in variable bubble point problems. This is accomplished by means of a novel pseudo solution gas formulation.
An efficient method for including two-point upstream into fully implicit simulators, without increasing the Jacobian bandwidth, is described. The scheme is based on a fully implicit upstream mobility plus an explicit correction term derived from the two-point mobility formulation. In addition a new method called centralized upstream is given. The new method has less truncation error then two-point upstream, and is little more difficult to implement.
A modified Crank-Nicholson method is described for reducing the time truncation error associated with large time steps in implicit models. The modified version does not exhibit the usual stability problems associated with the Crank-Nicholson method on nonlinear problems.
A section on well models shows how a simple enhancement of conventional well models can be used to account for the position of a well within a grid block. It is also shown how to introduce a multiblock well completion into an implicit simulator without destroying the block-banded form of the Jacobian, or without increasing the bandwidth.
An efficient iterative solution method is described for the sparse block-structured Jacobians. The method extends the SIP factorization to block form and uses minimizations and orthogonalizations to accelerate the convergence rate.
Several applications and examples are provided. A water coning example is included to show the stability and convergence characteristics of the Newtonian iteration. A vertical cross-section oil resaturation problem with variable bubble point is used to illustrate the pseudo solution gas formulation. The modified Crank-Nicholson method is applied to a one-dimensional Buckley-Leverett type problem.
Evaluation of Procedures and Instrumentation Available for Time-Temperature Stability Studies of Crosslinked Fluids
Authors: Conway Michael W. , Pauls Richard W. , Harris Lawrence E. 
Published: December 2007

ABSTRACT
The rheological characterization of crosslinked fracturing fluids, even at ambient conditions, has proven to be a very difficult task. Because no unique Theological parameters exist for time-shear dependent fluids, the utility of n’ and K’ data gathered on these fluids depends entirely on the validity of the methodology used to prepare and evaluate the fluids. Since the prediction of fracture geometry and proppant placement is highly dependent on the n’ and K’ values used, it is imperative that the rheo-logical parameters are representative of the fluid that is used in the field.
Present methods used to prepare cross-linked fluids for rheological characterization will be discussed. Criteria useful in evaluating laboratory procedures will be presented.
Only a limited amount of instrumentation is available for measuring the rheological properties of fluids at temperatures greater than 212°F (100°C). The inherent limitations of the available equipment will be reviewed and data showing the effect of procedural variations will be presented. Procedures aimed at providing time-temperature stability data will also be presented.
Visual Logging for Inspection and Troubleshooting
Authors: Davis Ken E. , Fleniken John A. 
Published: December 2007

ABSTRACT
The waterwell industry has been using submergible television cameras for years to aid them in casing inspections and troubleshooting wells. Their success ratio has been outstanding but the oil industry and others have only had limited success. The reason is usually the lack of clarity in the drilling or work-over fluid. Displacement of these fluids is generally affected by fluid density, fluid velocity, temperature and the size pipe in which the displacement is being made. This large number of variables indirectly affects water clarity in that you must displace the dirty drilling or completion fluid before a television camera can be used. Field tests have been conducted on the effects of these variables and the results offer suggestions for the solution of these associated problems. Downhole pictures are presented showing the effects of the aforementioned variables as well as unique failures of casing and the positions of various types of lost equipment. Some open hole logging is also presented.
Short Term Pressure Build-Up Analysis in Vertically Fractured Wells, Constant Rate and Variable Rate Cases
Authors: Beardall Terence J. 
Published: December 2007

ABSTRACT
Empirical approximation equations to the uniform flux and finite conductivity vertically fractured well models are presented. The equations are of similar form and can be superposed to derive a wide range of analysis techniques analagous to those for radial flow. In this paper, both constant rate and variable rate build-up cases are discussed. New plotting methods are derived which extend the normal Horner radial flow straight line back to much earlier shut-in times. The techniques are particularly useful in the analysis of short term pressure build-ups, which do not reach pseudo-radial flow.
Analysis of Vertical Fracture Length and Non-Darcy Flow Coefficient Using Variable Rate Tests
Authors: Pascal H. , Quillian Ronald G. , Kingston D. J. 
Published: December 2007

ABSTRACT
In this investigation, a new method is presented for predicting both the non-Darcy flow coefficient and vertical fracture length based upon single-point, variable flow drawdown tests of shallow, low permeability gas reservoirs. The mathematical model simultaneously incorporates the effects of non-Darcy flow and variable rate expressed as a continuous function of time, thus providing a corrected pressure-drawdown versus time relationship.
Pascal and Quillian1 described a method of analyzing variable flow tests where rate variation, usually declining during the test, is considered a continuous function of time. Solutions proposed in the foregoing article offered credible values for permeability and skin when matched with well production histories. Pascal, Quillian and Kingston have now expanded upon the basic concepts presented under reference 1 to provide solutions for vertical fracture length and the non-Darcy flow coefficient, using single-point variable flow data, resulting in a comprehensive model for analyzing transient pressure behavior.
A correlation between the non-Darcy flow coefficient and permeability is also proposed.
In low permeability gas reservoirs, the effects of variable (declining) rate become less apparent as flow time is extended. Conversely, the influence of non-Darcy flow becomes more dominant with increasing flow time.
The model is illustrated using several field from hydraulically fractured gas wells in a low permeability reservoir.
Inclusion of Radial Flow in Use of Permeability Distribution in Waterflood Calculations
Authors: Ache Paul S. 
Published: December 2007

Abstract
In 1949, William E. Stiles presented an article entitled, "Use of Permeability Distribution in Water Flood Calculations" in which he outlined a method for prediction of water flood performance. In the method Stiles derived equations which were based upon the assumption that the direction of fluid flow from an injection well was in a linear direction. These equations were mathematically derived by a statistical presentation of permeability data.
This paper introduces to the method the fact that initially the direction of fluid flow from an injection well is radial and then continues to treat the direction of flow in three distinct periods. The first is radial flow; the second is a period of transistion from radial to linear flow; and the third is after reservoir fill-up when it is assumed that linear flow conditions do predominate. Equations are then derived for the radial flow period which express water cut and the commensurate fraction of water flood oil recovered in terms of dimensionless permeability. Additional modifications are also suggested in application to field performance.
New Steel Alloy and Certification Procedure for High Pressure Wellheads
Authors: Burley J. D. , Greer J. B. , Royer C. P. 
Published: December 2007

ABSTRACT
Deep, abnormal-pressure, sour gas well development has resulted in the investigation of alternate alloys for use in high-pressure wellhead equipment. Evaluation of more traditional alloys produced results that were considered to be deficient for thick-wall, high-pressure equipment. This paper describes laboratory evaluations of a chromium-one percent molybdenum low alloy steel family that provides more uniform throughwall physical properties and manufacturing experience with this alloy for a high-pressure wellhead application. Also described is a certification procedure that more closely approximates the metallurgical structure and physical properties for large, thick-wall, high-pressure equipment.
New Instrumentation for Managing Sand-Problem Prone Fields
Authors: Stuivenwold P. A. , Mast H. 
Published: December 2007

ABSTRACT
Sand influx in oil and gas wells may cause serious erosion problems and result in substantial deferment in production. Tools have been developed for continuously monitoring sand production both at surface and downhole. These tools are applicable in dry and wet gas and single-phase liquid. They are now being applied in field operations. A prototype sand detector for multi-phase flow has been developed and successfully tested in the field.
An Automatic Timestep Selection Scheme for Reservoir Simulation
Authors: Jensen Ole K. 
Published: December 2007

ABSTRACT
The literature concerning timestep selectors is reviewed with discussion of applications to reservoir simulation.
A first order predictor-corrector method is applied to automatically select the time-step size in a finite difference steam injection reservoir simulator. The step size is estimated from the first neglected term in the series expansion; and a set of rules is developed for accepting new step sizes. Comparisons are made with a commonly used method which limits the time step based on the linear extrapolation of maximum changes of key variables. The comparisons show reductions in the number of time step used; easier usage and to some degree elimination of rapidly oscillating timestep.
Three Dimensional Permeability Measurements
Authors: Morita Nobuo , Gray K. E. 
Published: December 2007

ABSTRACT
This paper provides theory and experimental procedures to calculate principal permeabilities and directions from data obtained with a whole core type permeameter which has radial and axial flow measurement capabilities with two openings attached to cylindrical curved surface. The conventional plug method to determine anisotropic permeability was also modified to improve its accuracy; plug number and sample spacing were rigorously designed using error sensitivity numbers.
To check the validity of the apparatus, experiments were run using anisotropic Berea sandstone.
Foamed Acid Stimulation: Success in the Illinois and Michigan Basins
Authors: Ford William G. F. , Burkleca Lee F. , Squire Kenneth A. 
Published: December 2007

ABSTRACT
Foamed acid has been used successfully in the stimulation of oil and gas wells in the Illinois and Michigan basins. Advantages derived from the use of foamed acid in fracture acidizing treatments are presented. Results have shown that foamed acid outperformed conventional acid as a means of increasing production when used in fracture acidizing treatments. This paper discusses various aspects of job design and summarizes treatment results.
Analysis of an Extended Well Test to Identify Connectivity between Adjacent Compartments in a North Sea Reservoir
Authors: Gringarten A. C. 
Published: December 2007

Abstract
The paper demonstrates the usefulness of extended well tests and advanced interpretation techniques to complement seismic information with an example from a North Sea reservoir. This reservoir is heavily faulted but seismic indicated that the faults were discontinuous, thus suggesting good communication between the various parts of the reservoir. To verify this, tests were run on the two wells already drilled: an extended four month test on a vertical well, followed by a four and a half month shut-in; and a conventional test on a horizontal well. The extended test was analyzed in both the conventional way (one flow period at a time) and by deconvolution of the entire pressure and rate histories. The combination of the interpretations of the tests on both wells allowed to delineate compartments in the reservoir, to assess their connectivity and to correct the seismic information.
The paper illustrates the difficulty of interpreting data in the conventional way, as most interpretable flow periods are short (200 hours maximum) compared to the length of the test and individually may be misleading, as derivative shapes tend to be dominated by features reflecting the way log derivatives are calculated rather than by the geology. It is shown that deconvolution is free from these limitations and provides a much clearer picture of the well behavior.