bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thermal Stability of Foam Additive in Steamflood Core Tests
Authors: Allawzi M. A. , Patton J. T. 
Published: December 2007

ABSTRACT
The thermal degradation of a commercial steam-foam surfactant, was evaluated in flow under simulated reservoir conditions. Degradation was studied at 1500 psi in a conventional slim-tube flow model mounted in a furnace. The model was packed with core material taken from the steamflood area of Wilmington's Tar Zone reservoir.
The rate of decrease in additive concentration over time indicated the degradation reaction is first order. The effect of temperature on the degradation rate constant, k, was determined using the Arrhenius equation.
A mathematical model is presented that allows the calculation of thermal degradation at any temperature as a function of time. The model can be incorporated in advanced reservoir simulators such as CMG's STAR model to predict surfactant concentration at any point in the reservoir. Surfactant half-life is 221 days at 200°F, decreasing to 37 days at 500-°F.
Fluid Production Enhancement by Exploiting Sand Production
Authors: Geilikman M. B. , Dusseault M. B. , Dullien F. A. 
Published: December 2007

ABSTRACT
Sand production instability is considered as a result of wellbore fluid pressure reduction (drawdown) below some critical level. A continuum model for sand production is developed by considering coupling of fluid flow and rate-sensitive plastic flow of granular matrix. The model provides a physical mechanism of yielding front propagation away from the wellbore as the process of sand production continues. Mass balance analysis leads to a relation between cumulative sand production and the current yielding front location. Short-term enhancement of fluid production because of simultaneous sand production turns out to be dependent not only on instantaneous sand flux, but also on the current radius of the yielded zone around wellbore, that is, the history of sand production for the well. Long-term enhancement is stipulated mainly by appearance of yielded, highly permeable zone around the wellbore.
CO2 Foam Field Verification Pilot Test at EVGSAU: Phase IIIC—Reservoir Characterization and Response to Foam Injection
Authors: Harpole K. J. , Siemers W. T. , Gerard M. G. 
Published: December 2007

ABSTRACT
This paper summarizes the comprehensive reservoir characterization effort for the foam pilot area and discusses the response to foam injection in the CO2 Foam Field Verification Pilot Test conducted in the East Vacuum Grayburg San Andres Unit (EVGSAU) in New Mexico. A detailed study of the pilot pattern geology provided an understanding of the major controls on fluid flow in the foam pattern. Pattern performance data, falloff testing, profile surveys, and interwell tracer results were integrated into the geologic model to guide project design work and provide a framework for interpretation of foam performance. Localized regions of high permeability resulting from solution enhancement of the matrix pore system appear to be the primary cause of the early CO2 breakthrough and channeling of injected CO2 toward the problem production well in the foam pattern. Positive response to foam injection is indicated by reduced injectivity and injection profile data in the foam injection well; by results from time sequence monitor logging in the observation well; and by changes in production performance in the high GOR, "offending" production well in the foam pattern. Hall plots and pressure falloff testing were used to measure in situ changes in fluid mobility near the foam injection well. Time sequence logging responses at an observation well located 150 feet from the foam injector provided evidence of changes in fluid flow patterns in response to foam injection. Positive response to foam injection is further evidenced by changes in the C02 production and oil rate performance at the "offending" production well in the foam pilot pattern.
Evaluation of Flooding Strategies for a North Sea Reservoir Using Stochastic Techniques To Model Heterogeneities
Authors: Samuelsen E. T. , Langlais V. N. , Svanes Tarald , Dalen Vilgeir , Tyler K. J. 
Published: December 2007

ABSTRACT
An element model of the Raude member of the Statfjord formation in a North Sea field has been used for development of a long term drainage strategy. The heterogeneities of this fluvial reservou call for the use of stochastic techniques when modelling IOR processes. This approach makes it possible to create more realistic heterogeneity patterns than conventional interpolation techniques, and to produce several possible distributions of facies and petrophysical variables in a simple manner. Facies distribution has been modelled by a technique combining marked point processes and Gaussian random fields. It produces channel belts in 3D with their specific characteristics such as sinuosity. The petrophysical variables are simulated subsequently on a fine grid, taking into account the facies distribution. Upscaling is performed to provide input to the flow simulator. Water, gas and water alternating gas injection schemes are the investigated flooding strategies. Sensitivity tests are performed on different stochastic images and selected parameters such as WAG period, residual oil saturation after water-flooding, well location and petrophysical parameters. In this reservoir WAG injection improves the recovery from the element compared to water or gas injection. The average permeability appears to be as important as different spatial facies distributions. The residual oil saturation has significantly more influence on the recovery than considering spatial distributions of facies and permeability.
Daqing Oil Field: The Success of Two Pilots Initiates First Extension of Polymer Injection in a Giant Oil Field
Authors: Delamaide Eric , Corlay Philippe , Demin Wang 
Published: December 2007

Abstract
Two highly successful polymer pilot experiments were carried out between 1987 and 1993 on the Daqing oil field (People Republic of China) after favorable laboratory results and preliminary reservoir studies.
The Daqing oil field is a fluvio-deltaic formation with several sand beds and great heterogeneities. The oil is slightly viscous (9.5 cp), water is fresh and the temperature is 45°C, making the conditions favorable for polymer injection.
Each pilot consisted of 4 injectors and 9 producers. One pilot was devoted to one reservoir, whereas simultaneous injection into two reservoirs was performed in the second pilot.
Polymer injection was started in 1990 with a 915-ppm-solution of Polyacrylamide. Approximately 0.6 PV of solution was injected in each pilot, yielding a significant decrease in the water-cut and a respective oil production of 73 120 m3 and 1 1 8 950 m3 in April 1993.
The results of the pilots were matched with a numerical simulator and interpreted in terms of reservoir description. The injection parameters were optimized in terms of viscosity and slug size, in order to extend the process to the whole field.
The sensitivity of the process to the reservoir heterogeneity was also considered.
A New Mathematical Model and Experimental Validation of Multicomponent Adsorption
Authors: Song Fu Yin , Islam M. R. 
Published: December 2007

ABSTRACT
Numerical simulation of multicomponent adsorption (such as in foam-forming surfactants, lignosulfonate, polymer/surfactants, etc.) is still at an early stage. Mathematical models of multicomponent adsorption and desorption in a surfactant/rock system have not yet been well developed. In this paper, a mathematical model for multicomponent adsorption, based on surface excess theory, is presented. The mathematical model is validated through more than 30 experimental runs under a wide range of operating conditions. Several multicomponent mixtures were used in the experimental runs to observe the effects of surfactant concentration, chemical slug size, flow rate, rock properties, salinity of the surfactant solution, and temperature. With the application of lignosulfonate as a sacrificial adsorbate, the amount of surfactant adsorption can be reduced significantly. Polymer-surfactant solution flooding system is a economical way to increase the efficiency of chemical injection. Polymer has beneficial effects on surfactant adsorption though polymer itself still has strong adsorption at the solid/liquid interface relative to surfactant. Numerical simulation results showed excellent agreement with experimental data.
New Pressure Tool Development Yields Critical Bottomhole Data
Authors: Bond A. J. , Palisch T. T. , Oakley R. M. 
Published: December 2007

ABSTRACT
Development of a new pressure measuring tool has yielded critical bottom hole pressure data in the fields on the North Slope of Alaska. The new tool permits gathering bottom hole pressure and temperature data that previously was uneconomical to obtain. This paper outlines the development of the new pressure measuring tool, its application and the results obtained from the new data. Also presented are the large cost savings that have been realized through the use of this tool.
Improvements in Defining the Magnitude of the Minimum In-Situ Stress Using Hydraulic Impedance Testing and Pressure Derivative Analysis.
Authors: Branagan P. T. , Holzhausen G. R. 
Published: December 2007

ABSTRACT
Hydraulic Impedance Testing (HIT)1,2 is an easily applied transient pressure response method that can be successfully employed in determining fracture closure. In addition pressure derivative analysis when applied to fracturing and/or falloff data can readily define the actual changing flow regimes that exist within the fracture at any given time. Knowledge of the proper flow regime is a critical component in selecting the most appropriate analysis methods that should be used to define the minimum in-situ stress (σmin), i.e techniques based on linear or bilinear3 flow analysis. The combined diagnostic methodology that employs HIT and improved pressure derivative analysis4 when used in conjunction with conventional microfracturing techniques5,6 can substantially reduce the error in defining σmin. The results of several field tests will be used to illustrate the power and simplicity of these techniques in assessing what can often appear to be ambiguous pressure falloff data.
Analysis of Pressure Data From Heterogeneous Reservoirs: Wellbore Storage and Skin Effects
Authors: Chu Lifu , Reynolds A. C. 
Published: December 2007

ABSTRACT
We consider a well completed in a heterogeneous reservoir where permeability is a function of position and investigate the analysis of well-test pressure data influenced by wellbore storage and skin effects. Methods to estimate the pressure drop due to skin are presented. It is shown that if wellbore storage effects are small or can be removed by deconvolution, then an equivalent radial permeability distribution can be estimated. By combining this permeability distribution with the estimate of an appropriately defined skin factor, it is shown that reliable predictions of long-time well performance can be obtained.
Higher-Order Neural Networks in Petroleum Engineering
Authors: Kumoluyi A. O. , Daltaban T. S. 
Published: December 2007

Abstract
In this paper, we discuss the general application of higher neural networks, this follows from the successful application of such networks to the identification of well test models. During the course of the research, it was discovered that these networks have a large range of applications in petroleum engineering. Hence the objective of this paper is to give a background of higher order neural networks and their potential uses. Conventional neural networks have activation functions that are linear correlations of their inputs, whereas higher order networks have a non-linear correlation of their inputs. Higher order neural networks do not have wide practical applications due to the enormous amount of parameters (weights) associated with them. However, for certain problems these vast amount of weights are greatly reduced by constraining the architecture of the network. That is, problems that need to be classified regardless of some transformation groups such as translation, scaling and rotation. A typical example is the identification of well test models where standard type curves are translated both horizontally and vertically with respect to field data plots.
Practical Well Test Interpretation
Authors: Mattar Louis 
Published: December 2007

Abstract
Well Test Interpretation involves much more than Pressure Transient Analysis. It includes scrutinizing the field notes, the surface operations, the equipment and the wellbore configuration. It means incorporating geological information and production information; adjusting the measured data to reservoir conditions and accounting for multiphase effects both in the wellbore and in the reservoir; recognizing that wellbore effects during a buildup are different from those during a drawdown; in short, integrating the practical issues with the theoretical analysis.
Field examples will be presented to illustrate these effects. Ignoring these effects can lead to the wrong pressure transient analysis.
Roller-Vane Motor and Pump
Authors: Grupping A. W. 
Published: December 2007

Abstract
Roller-vane motors and pumps are positive displacement type rotating machines. They are of simple design, short, compact and lightweight. The mud motor is particularly suitable for short-radius directional drilling and well cleaning. The pump will lift a full range of volumes of oil, water or brine. The production motor/pump combination is an attractive alternative to other artificial lift methods as its efficiency is high, the pump speed is variable by control of the power fluid, the set can be installed in strongly deviated wells and can be installed/retrieved without pulling the tubing.
Applications for Multiphase Compartmentalized Material Balance
Authors: Ehlig-Economides C. A. 
Published: December 2007

Abstract
Material balance computations provide a mechanism for estimating the volume of fluids in place underground. Frequently the material balance is applied without using exhaustive static data from geophysical, geological and petrophysical analyses that would provide an independent estimate for fluid volumes in place. Workstations offer a possibility to integrate data from many sources and enable highly detailed visualizations of delineations of reservoir limits, correlations of geological features among wells, potential barriers to flow, and reservoir heterogeneity. The reservoir model derived from the workstation environment contains sufficient detail to discourage the conventional global material balance approach as too simplistic. Instead, partitioning the reservoir into compartments, or portions of the reservoir with similar fluid flow characteristics and a common recovery mechanism, offers a means to incorporate the volumetric estimates from static data into material balance equations, thus enabling the use of these equations for additional purposes.
Fox, et al.1 introduced the compartmentalized single phase material balance as a means for characterizing intercompartment communication and effective compartment volumes and for interpreting pressure transient well tests and formation test pressures in heavily faulted formations. This work extends the concept to multiphase and multiwell cases and for vertical compartmentalization in addition to horizontal.
The objectives of the compartmentalized material balance introduced in this work are to validate compartment volumes, fluid PVT behavior, rock compressibility, and production data, and to quantify and characterize flux between compartments. This paper details the computations used and some of the theory behind them. Then practical applications for this type of model are described.
Practical Aspects of Compositional Simulation
Authors: Wattenbarger Robert A. 
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Compositional reservoir simulation is a relatively new facet of reservoir simulation. Although the mathematical equations are somewhat more complicated than for conventional reservoir simulation, the concepts can be simplified by stating that we are simultaneously modeling (1) three-phase Darcy flow, (2) the movement of each individual hydrocarbon component through the reservoir, and (3) phase equilibrium at each point in the reservoir. The phase equilibrium between gas and oil is determined by the K-values which are used for each particular temperature, pressure, and composition.
Compositional simulation is applied to a variety of reservoir fluids but the most common application is to volatile oil and gas condensate reservoirs. For these reservoirs, gas cycling, waterflooding, and primary depletion can be modeled for the purpose of making economic comparisons and making decisions.
The cost and computational speed of compositional simulation depends partly on the number of components which are being modeled. A typical computational requirement is 0.1 seconds/mesh point/time step on a CDC 6400 computer for a 12 component system.

Introduction
Fortunately, many reservoirs contain fluids which have a simple type of phase behavior and physical properties. It is sufficiently accurate for these fluids, to represent the amount of gas in solution as an empirical function of pressure only. The densities of gas and reservoir oil are related to surface densities through formation-volume-factors which are empirical functions of pressure. Viscosities are also empirical functions of pressure. pressure. Viscosities are also empirical functions of pressure. Such simple systems are sometimes called "black-oil" systems. This is the type of fluid system which has been the basis of most of the reservoir simulation technology developed in recent years.
Comparative Analysis of Successful Application of EOR in Russia and CIS
Authors: Basnieva I. K. , Zolotukhin A. B. , Eremin N. A. , Udovina E. F. 
Published: December 2007

Abstract
The oil industry of the former Soviet Union (FSU) has extensive experience in enhanced oil recovery (EOR) methods. Variety of conditions, both geological and geographical, require systematic analysis of the applicability of EOR methods under different reservoir conditions.
Fuzzy logic comparative analysis enabled the identification of the main reservoir/fluid parameters that have an impact on the success of EOR methods. Analysis was done on EOR methods such as steam injection, polymer flooding, surfactant flooding, group of the gas injection methods, and CO2-flooding. The data base created by the authors includes more than 800 EOR projects with a substantial part of them carried in the FSU. Several examples of the EOR feasibility study are discussed in the paper.
The approach described in this paper allows the selection of secondary/tertiary oil recovery methods which are most promising for the given geological conditions. This reduces the number of diverse field performances and, hence, shortens the risk and uncertainty in the decision making.
Measurements of Complex Electrical Conductivity and Fluid Permeability In Porous Rocks at Raised Confining Pressures
Authors: Glover Paul W. J. , Meredith R. G. , Sammonds P. R. , Murrell S. A. F. 
Published: December 2007

Abstract
Combination of electrical and permeability measurements provides a great deal of information about changes in pore and crack networks as saturated rocks are deformed. Complex electrical parameters measured as a function of frequency provide information on the internal surface topology of the rock, information that is of prime importance to explanation of the way fluid permeability of rocks varies with confining pressure and deformation. Tests made at raised hydrostatic confining pressure and during uniaxial deformation until failure, show how processes of pore/crack compaction, dilation and inter-linking control both the electrical conductivity and the fluid permeability of the rock.
Capillary Forces: The Neglected Factor In Shale Instability Studies?
Authors: Forsans Thierry M. , Schmitt Laurent 
Published: December 2007

Abstract
Most phenomena in shale drilling instabilities have only been proved in laboratories, on reconstituted, outcrop or core samples. Partial saturation is evidenced for these samples, its origins explained and its consequences detailed. A model is proposed for the calculation of the apparent compressive strength of a rock from its pore size distribution and moisture content. Effects of capillary pressures are presented in various shale/fluid inhibition tests and some classical interpretations turned down. Last, a rehydration procedure is presented, which has been validated on a low permeability shale.
A Non Iterative Technique for Solving Parabolic Partial Differential Equation Problems
Authors: Sheffield M. 
Published: December 2007

Abstract
This paper presents a new noniterative difference technique which may be used to solve parabolic partial differential equation parabolic partial differential equation problems, including those arising in the prediction problems, including those arising in the prediction of fluid flow in a porous media. It is shown that this difference technique is unconditionally stable and is suitable to solve engineering problems. A comparison is made between the new problems. A comparison is made between the new method and two other stable noniterative difference techniques, the Saul'ev technique and the noniterative ADI technique. Of the two problems worked as examples, the new method is problems worked as examples, the new method is most efficient for the elongated grid problem, and noniterative ADI is most efficient for the square grid problem.
Introduction
Since the introduction of high speed computers, a reservoir engineering research goal has been to develop increasingly efficient methods of predicting reservoir fluid movement. Various methods have been developed or used by petroleum engineers to predict the performance petroleum engineers to predict the performance of an oil field. The major emphasis in the solution of partial differential equations simulating multiphase fluid flow has been the finite difference approach, which can be summarized by the following series of steps.
The reservoir or section of a reservoir is characterized by a series of mesh points wit varying rock and fluid properties simulated at each point. The partial differential equations which describe the fluid flow are written. At each mesh point the partial differential equations are replaced by difference equations. The resulting equations are solved [sometimes iteratively to obtain an approximate solution to the original partial differential equation problem.
This paper presents a new technique for replacing the differential equation at each mesh point by a difference equation.
Difference equations are evaluated in terms of the stability, consistency and order of accuracy. Usually these items are discussed in regard to solution of the diffusivity equation, a linear partial differential equation for sore uniform rectangular mesh covering the region of interest. The same approach is used here. However, it should be noted that the conclusions reached considering a linear partial differential equation and a uniform rectangular mesh are not always applicable to petroleum problems where the differential equations are nonlinear and the mesh is often not uniform.
DESCRIPTION OF THE DIFFERENCE TECHNIQUE
In this paper a new two-step noniterative difference technique is presented.