bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pilot Testing of a New Generation of Induced Gas Flotation Equipment
Authors: Movafaghian Shaya , Chen James , Wheeler Stephen Scott , Guidry R. W 
Published: December 2007

Summary
Induced gas flotation (IGF) technology is well-known in the oil industry for effectively treating produced water to meet environmental oil-in-water discharge requirements.
This paper presents technical considerations for development of a new generation of IGF units, a discussion of the process kinetics, actual operating data, and performance analysis of a full-sized, four-cell WEMCO* cylindrical depurator.
A pilot test program was developed and executed in collaboration with ChevronTexaco Overseas Petroleum on platformgathering-station Mike, located offshore in the Cabinda Province, Angola. Pilot data indicate that the flotation kinetic rate for oil removal from a four-cell cylindrical depurator is comparable with a conventional depurator.
Cylindrical depurator design captures the main technical advantage of conventional, mechanical IGF units for effective oil-particle flotation and offers the promise of fewer maintenance issues as well as viable alternatives for higher-pressure applications.
Field data validate theoretical predictions for the performance of the cylindrical depurator.
The Quality Map: A Tool for Reservoir Uncertainty Quantification and Decision Making
Authors: da Cruz Paulo S. , Horne Roland N. , Deutsch Clayton V. 
Published: December 2007

SummaryThe parameters that govern fluid flow through heterogeneous reservoirs are numerous and uncertain. Even when it is possible to visualize all the parameters together, the complex and nonlinear interaction between them makes it difficult to predict the dynamic reservoir responses to production. A flow simulator may be used to evaluate the responses and make reservoir management decisions, but normally only one deterministic set of parameters is considered, and no uncertainty is associated with the responses or taken into account for the decisions.This paper introduces the concept of a "quality map," which is a 2D representation of the reservoir responses and their uncertainties. The quality concept may be applied to compare reservoirs, to rank stochastic realizations, and to incorporate reservoir characterization uncertainty into decision making (such as choosing well locations) with fewer full-field simulation runs.The data points necessary to generate the quality map are obtained by running a flow simulator with a single vertical well completed in all the layers and varying the location of the well in each run to have good coverage of the entire horizontal grid. The quality of the horizontal cell in which the well is located is the cumulative oil production after a long production time.The geological model uncertainty is captured by generating multiple stochastic realizations and building a quality map for each realization. The quality maps of all the realizations provide a distribution of quality values for each cell of the map grid. A mean quality map can be obtained by taking the expected value for each cell, and a map of quality uncertainty can be obtained by taking the standard deviation of the distribution for each cell.If a loss function is specified, an L-optimal quality map can be generated by retaining, for each cell, the quality value that minimizes the expected loss. This map allows us to locate wells accounting for the geological uncertainty as well as for the risk profile of the decision maker.The methodology for building the quality map is presented in detail, and the applications of the map are demonstrated with 50 realistic reservoir models.
A New Biopolymer-Free, Low-Solids, High-Density Reservoir Drilling Fluid: Laboratory Development and Field Implementation
Authors: Horton Robert L. , Tresco Kim O. , Dobson James W. , Bye Gry Kristvik , Knox Dave A. , Svoboda Charles F. , Foxenberg William E. , Green Taylor C. 
Published: December 2007

SummaryLow-solids, brine-based reservoir drilling fluids (RDFs) are widely accepted as beneficial to optimizing compatibility with the completion design while minimizing fluid-related formation damage. Traditionally, the maximum density attainable with a low-solids fluid has been limited because of either the prohibitively high cost of the required base brine or the poor performance of viscosifying biopolymers in a dense, divalent cationic environment.An RDF has been developed that exhibits unusually high quality rheological behavior in high-density calcium- and zinc-based brines without the aid of a biopolymer. The new fluid shows a unique shear-thinning rheological profile that features a relatively low high-shear-rate viscosity along with a relatively high low-shear-rate viscosity (LSRV). This behavior is highly unusual in high-density, brine-based RDFs. A result of this behavior is that effective hole cleaning is provided without generating excessive high-shear-rate viscosities that lead to excessive equivalent circulating densities (ECDs).The first field trial of this fluid was on the reservoir section of Well 34/10 I-1-AH in the Gulfaks Satellites Development in the Norwegian sector of the North Sea. Fluid properties during pretesting, mixing, drilling, and completion of this section are detailed in this paper.
Reservoir Simulation Using Bottomhole Pressure Boundary Conditions
Authors: Kuniansky Joseph , Hillestad J. G. 
Published: December 2007

Abstract
This paper presents results derived from potential flow theory for single-phase flow in the region near an injection or production well. The relations obtained are directly applicable to reservoir studies where coarse grid systems, which cannot account for near-wellbore flow, are used to describe flow within the reservoir.
Near-wellbore effects have received only minor attention in the literature.1–7 This work concentrates on a general solution to this flow problem. Relations are derived for a system with one or two wells located in a rectangular area and for n wells located in an infinite area. The paper also gives a method that accounts for areal flow behavior near a wellbore in cross-sectional simulations. Comparisons of the analytical results with computer results using Peaceman's5 relationship for the effective wellbore radius of a simulator well show good agreement for cases where the wells are located at the block center regardless of the grid size or the position of the well block within the grid system. The paper also illustrates how pressure boundary conditions can be applied in cases where the wells are not located at the center of a grid block. The derived relationships are applicable for a simulator based on either five- or nine-point formulations.
Strategies for Sizing Particles in Drilling and Completion Fluids
Authors: Suri Ajay , Sharma Mukul M. 
Published: December 2007

SummaryTo minimize formation damage caused by drill-in and completion fluids, solids must be sized to satisfy two important criteria. First, they must be large enough to not invade the rock, and second, they must be small enough to form filter cake that effectively filters drill solids and polymers from entering the formation. These criteria, when used together with the model presented in this paper, quantitatively determine the particle size that should be used in drill-in fluids for a given formation permeability, overbalance pressure, and mud formulation.A model is presented that estimates the depth and degree of formation damage caused by solids of widely different sizes present in drilling or completion fluids. The depth of damage and permeability loss is calculated after the invasion of the mud and also after flowback. The effect of the particle size distribution in the fluid, particle concentration, overbalance pressure, and permeability of the formation are studied. It is demonstrated that particle invasion and flowback processes are largely dependent on the particle size in the mud and the permeability of the formation. The results of the model are shown to agree well with mud filtration experiments.To better estimate the particle size distribution in drill-in and completion fluids, different methods for measuring particle sizes were investigated. These results show that the measured particle sizes can vary over two orders of magnitude depending on the technique used and on sample preparation. Based on a comparative analysis of several samples, light-scattering techniques are recommended for measuring the particle size distribution. Recommendations for sample preparation are also provided.
Time Scaling of Rates of Produced Fluids in Laboratory Displacements
Authors: Laroche Catherine , Chen Min , Yortsos Yannis C. , Kamath Jairam 
Published: December 2007

Summary
In a recent study,1 it was shown that the ratio of the flow rates of the produced fluids in an immiscible displacement can be used to identify geometrical and petrophysical characteristics of a reservoir. In this paper, we develop an extended version of this approach and apply it to displacements in 1D laboratory cores. Because of the possible importance of capillary effects, we derive asymptotic theories for the time dependence of the produced fluid ratio in the limits where capillary is negligible and where it dominates, respectively. Attention is paid to the capillary end effect at the outlet and to late times.
It is shown that the exponent in the power-law dependence of the relative permeability to saturation, near its residual value, can be determined from a segment of the curve of the outlet fractional flow sometime after breakthrough. The asymptotic predictions are verified by obtaining an analytical solution to the full problem, including end effects, for a model case corresponding to Burgers' equation. Solutions are obtained for both drainage and imbibition. Experimental results for the high-rate displacement of some gas/ liquids pairs are then reported. In agreement with the theoretical predictions, a power-law segment in the outlet fractional flow curve can be identified before capillary effects set in. The exponents obtained are discussed in terms of pore-scale models for gas/liquid displacement.
Split Full Tensor Discretization Operators for General Hexahedral Grids
Authors: Edwards Michael G. 
Published: December 2007

Summary
A major assumption in many simulators is that the pressure equation always has a diagonal tensor. However, in many cases of practical interest, a full tensor matrix occurs. Three contributing factors that can give rise to a full tensor pressure equation are anisotropic media, upscaling (with cross-flow effects), and non-K-orthogonal structured and unstructured grids. The introduction of a full tensor approximation typically increases the support of the standard scheme on a logically rectangular grid from 7 to 27 nodes in 3D, which can increase 3D simulation costs by over 100%. In this paper, 3D full tensor operator splitting schemes are presented. These schemes maintain consistent full tensor approximations while only requiring diagonal tensor inversion.
New Numerical Schemes for Near-Well Modeling Using Flexible Grids
Authors: Ding Y. , Jeannin L. 
Published: December 2007

Summary
Control-volume schemes are discussed for the modeling of vertical wells using flexible grids.
The main difficulty of well modeling in reservoir simulation is the problem of the difference in scale between the reservoir size (several kilometers) and the wellbore radius (several centimeters). In applications, although the wellbore boundary can be discretized using flexible grids, the gridblocks in the vicinity of the well are usually not small enough compared to the wellbore radius, and the gridblock sizes vary, usually geometrically, in the radial direction from the well. This kind of grid makes the commonly used linear approach (that is linear with respect to coordinates of physical space) inefficient for near-well flow modeling.
In this paper, new numerical schemes, based on logarithmic approach, are proposed to improve the linear approach for nearwell modeling. In particular, a multipoint and a two-point flux approximation scheme are presented. These schemes can reduce the calculation errors for the dominant "singular" well flow and consequently give good results. The proposed approach can be used for any kind of flexible grid for near-well modeling.
A Neural Network Model for Prediction of Liquid Holdup in Two-Phase Horizontal Flow
Authors: Shippen Mack E. , Scott Stuart L. 
Published: December 2007

SummaryAccurately predicting the liquid holdup associated with multiphase flow is a critical element in the design and operation of modern production systems. This prediction is made difficult by complex phase distributions and the wide range of fluid properties encountered in production operations. Consequently, the performance of existing correlations is often inadequate in terms of desired accuracy and application range. This investigation focuses on the development of a neural network model, a relatively new approach that has been applied successfully to a variety of complex engineering problems. Data from five independent studies were used to develop a neural network for predicting liquid holdup in two-phase horizontal flow. A detailed comparison with existing empirical correlations and mechanistic models reveals that for this data set, the neural network model shows an improvement in overall accuracy and performs more consistently across the range of liquid-holdup and flow patterns.
History Matching Using a Streamline-Based Approach and Gradual Deformation
Authors: Gautier Y. , Nœtinger B. , Roggero F. 
Published: December 2007

SummaryReservoir engineers often have to deal with history-matching problems. This is time-consuming because of the many numerical simulations that have to be run and also because of the size of the models. Optimization, coupled with gradient-based methods, enables engineers to find efficiently a reservoir representation that respects all static and dynamic data. Nevertheless, for multiphase flow or for compositional problems, only relatively small models can be handled with a finite-volume flow simulator. On the other hand, streamline-based simulation provides accurate and fast estimates to various flow problems. Simulations can be performed on larger models than with a regular fluid flow simulator. Recently, streamline-based simulation has been used for history-matching problems. First, analytical gradients of production data with respect to a geostatistical parameterization have been computed for the tracer-flow case. The saturations along streamlines were moved using an analytical solution of the transport equation. This approach then has been extended to waterflood problems with varying boundary conditions.In our method, we compute gradients of the production data, of the saturation, and of the pressure. We use a 1D numerical simulator to move the saturation along streamlines. This method is more general than when analytical calculations are used; it is more accurate for complex flow patterns. It also can be extended to take into account other parameters such as gravity. The major drawback is that it is more time-consuming; the cost for the computation of each gradient is slightly smaller than the cost of a simulation. Nevertheless, this cost can be dramatically decreased by computing multiple gradients at the same time on different processors using parallelism.These gradients will be used to perform history matching using a nonlinear optimization package in conjunction with a geostatistical method, the gradual deformation method, enables the combination of multiple realizations of a permeability field and the continuous variation from one to another.We will apply our new method to perform a history match on a large-scale 3D synthetic example of a waterflood with a complex injection history.
A Review of Permeability-Prediction Methods for Carbonate Reservoirs Using Well-Log Data
Authors: Babadagli T. , Al-Salmi S. 
Published: December 2007

Summary
The prediction of permeability in heterogeneous carbonates from well-log data represents a difficult and complex problem. Generally, a simple correlation between permeability and porosity cannot be developed, and other well-log parameters need to be embedded into the correlation. The first part of this paper covers an extensive review of the existing correlations in the literature. The use of porosity and other petrophysical properties of rock in permeability prediction is discussed for carbonaceous rocks. This discussion also covers the usefulness of a wide variety of correlations developed using pore-scale (Kozeny-Carman, percolation, and fractal models) to field-scale models (well logs).
In the second part of the paper, a case study is presented. The data are obtained from a complex carbonate field in Oman. Conventional and nonconventional (mainly nuclear magnetic resonance, or NMR) well-log data are evaluated to seek the parameters reflecting a good correlation with permeability. After testing each independent variable against core permeability, the variables yielding the highest correlation coefficient (CC) are included in multiple regression analysis. Data collected from seven wells are used to obtain the permeability correlations for the whole field and for four geological units separately. The test of the correlations is achieved through the comparison of the estimated permeability values to core permeability. Finally, the correlations are compared with the core permeability of the eighth well (data from this well are not included in the development of the correlation) for validation. The correlations are obtained for the four geological units. Two of these units responded well to conventional well-log data; the other two units yielded reasonable correlations only with NMR log data.
Reservoir Modeling Methods and Characterization Parameters for a Shoreface Reservoir: What Is Important for Fluid-Flow Performance?
Authors: Jian F. X. , Larue D. K. , Castellini A. , Toldi J. 
Published: December 2007

Summary
Fifty reservoir models were built by using seven different modeling methods and varying a combination of reservoir characterization parameters using experimental design. These 50 models were all subjected to unconstrained fluid-flow simulation with an active aquifer and limited peripheral waterflooding without history matching. The results show that oil recovery from existing wells at 95% water cut ranges from 29 to 34% in these 50 models despite the large apparent visual differences between them. However, there are large differences (some greater than 200%) in water-breakthrough time, water cut, and cumulative water production. The differences in oil recoveries and water cut among all models were found to be largely related to horizontal permeability heterogeneities perpendicular to the shoreline direction.
Experimental design indicated that there were statistically significant differences in flow-simulation results associated with the definition of reservoir quality trends, 3D facies trends, and variogram range and direction. Do more complex, geologically realistic models provide the best frameworks for predicting flow performance in sandy shoreface reservoirs with good well control? Some of the simplest models we constructed provided flow-simulation results similar to those of the most complex and soft-data-conditioned models. What we do observe, however, is that the more soft conditioning data and the more complex geologic models tend to give a restricted range in full-field flow performance.
Otter: A 21-Kilometer Subsea Tieback With Dual Electric Submersible Pumps
Authors: Horn Mark , Coudeville Frederic , Bespalov Eugene , Butcher Howard 
Published: December 2007

Summary
The Otter field in the northern North Sea has been developed with three subsea production wells, each equipped with dual electric submersible pumps (ESPs). Dual ESPs were selected because they maximize well availability and minimize operating costs associated with workovers. The field is located 21 km from the host platform, making this development the longest subsea tieback with ESPs completed to date.
The equipment selected for the ESP system is described here, including downhole, subsea, and topside equipment. The rigorous testing program is also described, proving that ESPs could be successfully operated and controlled as well as receive data at such a distance from the variable-frequency drives.
The experience gained during the development and the operational philosophy developed for the Otter field will serve as a guide to future long-stepout or deepwater subsea developments by identifying critical components. Factors limiting the development of fields at greater stepouts are also discussed.
Conclusions on the steps required to implement a successful development and some of the pitfalls to avoid are listed in this paper.
Numerical Simulation of Mud-Filtrate Invasion in Deviated Wells
Authors: Wu Jianghui , Torres-Verdín Carlos , Sepehrnoori Kamy , Delshad Mojdeh 
Published: December 2007

Summary
Understanding the spatial distribution of fluids in the near-borehole region caused by mud-filtrate invasion is necessary for the accurate petrophysical interpretation of wireline measurements acquired in deviated wells. This paper provides a sorely needed petrophysical and fluid-flow template that can be used to integrate several wireline measurements into a unique model of petrophysical parameters in the near-borehole region of deviated wells.
We simulate numerically the physics of mud-filtrate invasion in vertical, horizontal, and highly deviated overbalanced wells. The numerical algorithm is adapted from a general 3D multiphase-fluid-flow simulator that is widely used in large-scale reservoir applications. Checks of numerical consistency and accuracy are performed against one commercial reservoir simulator. Emphasis is placed on describing the influence of mudcake buildup on the mud-filtration process. We approach the latter problem by introducing an effective-flow-rate function that describes the evolution in time of the rate of invasion of mud filtrate into rock formations. Parametric representations of the flow-rate function are derived on the basis of previously published laboratory experiments of mud circulation.
A sensitivity analysis quantifies the influence of several geometrical and petrophysical parameters on the spatial distribution of mud-filtrate invasion away from the borehole wall. These parameters include relative permeability, capillary pressure, permeability anisotropy, dipping layers, and degree of hydraulic communication between adjacent layers. Our simulations reveal the character of invasion profiles in complex geometrical environments taking place under realistic petrophysical conditions. We show that standard pistonlike descriptions of mud-filtrate invasion, commonly used in well-log interpretation, can lead to inaccurate interpretations of wireline measurements. An example is presented of the use of our simulation technique by calculating the sensitivity of borehole electromagnetic induction measurements to specific conditions of mud-filtrate invasion in a vertical well.