bluuebunny/crossref_metadata_2025_split huggingface dataset:
Succession-of-States Model for Calculating Long-Time Performance of Depletion Reservoirs
Authors: Lee K. S. , Miller M. A. , Sepehrnoori Kamy 
Published: December 2007

Summary
This study presents a new finite-element approach for directly calculating pseudosteady-state flow behavior for wells in depletion systems. The approach allows for spatially dependent reservoir properties, complex reservoir geometries, and multiple wells. Results are verified against long-time transient solutions reported in the literature for several regularly shaped systems. The paper also demonstrates application of the approach to field-scale problems. Results show that this approach provides a fast and accurate method for modeling the long-time behavior of depletion reservoirs. The approach is particularly applicable to single-phase volumetric gas reservoirs.
A bounded reservoir with wells producing at constant rate will exhibit pseudo steady-state behavior after the end of typically short-lived infinite-acting and transition flow periods. This study develops a new approach for directly calculating pseudosteady-state flow behavior without solving the full time-dependent form of the diffusivity equation. This approach can be applied to the linearized forms of the diffusivity equation for either single-phase liquid or gas flow. A finite-element method is used that allows for spatially dependent reservoir properties, complex reservoir geometries, and multiple wells. The first part of this paper presents a verification of the approach by comparing results for some regularly shaped systems against full-transient solutions reported in the literature.
For the simulation of field-scale problems with multiple wells of differing production rates, a well model based on a near-wellbore approximation of the pseudopressure distribution during pseudosteady-state is introduced to reduce the concentration of elements near wells. The second part of the paper demonstrates application of the direct pseudosteady-state concept to actual reservoir problems. To account for rate changes during extended production periods, the pseudosteady-state equation was solved successively for each flow period and combined with an overall reservoir material balance analysis.
Results from this study show that this approach provides a fast and accurate method for modeling the long-time behavior of various types of reservoirs under depletion conditions. The approach is particularly applicable to single-phase volumetric gas reservoirs.
Design and Installation of a Cost-Effective Completion System for Horizontal Chalk Wells Where Multiple Zones Require Acid Stimulation
Authors: Thomson D. W. , Nazroo M. F. 
Published: December 2007

Summary
An innovative completion design that allows multiple acid fractures to be performed in horizontal subsea chalk formation wells with a single trip into the wellbore has recently been codeveloped by a major North Sea operator and an oilfield engineering/manufacturing/service company. The project was begun to develop a system that would allow multiple acid stimulations to be efficiently performed in the shortest possible time in the North Sea Joanne field. The system ultimately developed allows acid stimulation of up to 10 different zones in a single trip with no through-tubing intervention. The first well in which this new technique was used had seven zones, and three additional wells with 10 zones each were later completed. This paper presents the development of this system and case histories of the first four subsea wells requiring stimulation.
The key element of the system is a multistage acid fracture (MSAF) tool that is similar to a sliding sleeve circulating device and is run in the closed position. Up to nine MSAF tools can be run in the completion with isolation of each zone being achieved by hydraulic-set retrievable packers that are positioned on each side of an MSAF tool. Each sleeve contains a threaded ball seat with the smallest ball seat in the lowest sleeve and the largest ball seat in the highest sleeve. With this system, stimulation of 10 separate zones is accomplished in 12 to 18 hours. A unique procedure that lubricates various sized, low specific gravity (SG) balls into the tubing and, then, pumps them to a mating seat in the appropriate MSAF tool to seal off the stimulated zone is used. This allows stimulation of the next zone, which is made accessible by opening the sleeve.
This technique provided a substantial reduction in the operation time normally required to stimulate multiple zones and allowed the stimulations to be precisely targeted within the reservoir. The case history data provides comparisons in operation times between traditional stimulations and this new method, as well as the significant enhancements to cost efficiency that resulted from its use. Additionally, this completion method allowed the stimulations to be designed and matched to the requirements of each reservoir zone, which provided the most cost-efficient treatments possible.
A Three-Layer Hydraulic Program for Effective Cuttings Transport and Hole Cleaning in Highly Deviated and Horizontal Wells
Authors: Nguyen Desmond , Rahman S. S. 
Published: December 2007

SummaryA new mathematical model is presented that enables the prediction of various modes of cuttings transport in highly deviated to horizontal annuli that have been observed in laboratories. The model consists of three components: a bed of particles of uniform concentration, a dispersed layer in which particle concentration is varied, and a fluid-flow layer that could be a clear fluid or a turbulent suspension. The model predictions exhibit good agreement with experimental observations.
Measuring Compaction and Compressibilities in Unconsolidated Reservoir Materials by Time-Scaling Creep
Authors: Dudley J. W. , Myers M. T. , Shew R. D. , Arasteh M. M. 
Published: December 2007

Summary
A testing procedure and analysis method is proposed that gives compaction and compressibility data that are independent of test duration for unconsolidated sands. Compaction data on unconsolidated sand material [including several Gulf of Mexico (GOM) reservoirs] derived from this method are presented. Tests on twin plugs give essentially the same stress-strain data for test durations from one day to three months. This occurs because of a fundamental time-scaling property of these unconsolidated materials. The creep behavior is modeled with a fractional power law dependence with time, which represents the Voigt material model having an extremely broad distribution of relaxation times. This analysis indicates that the characteristic relaxation times of these materials are measured in decades or longer. Creep equilibrated tests are, therefore, impractical and not relevant to a reservoir that will be depleted in one or two decades. Analysis of the power law creep parameters indicates the creep behavior is consistent at higher stresses among the materials tested. The creep parameters scale with stress and provide a means of decoupling the time-dependent behavior from the stress-strain behavior.
Type Curves for Analysis of Afterflow-Dominated Gas-Well Buildup Data
Authors: Maer N.K. 
Published: December 2007

A set of type curves is described that permits estimation of near-wellbore damage or stimulation from the afterflow-dominated portion of a pressure buildup test in a gas well. The result is portion of a pressure buildup test in a gas well. The result is an improved estimate of damage or stimulation relative to that obtained with constant fluid-property analyses of afterflow-distorted data.

Introduction
The conventional semilog plot of pressure buildup data is commonly used to determine formation permeability and, by means of the skin factor and flow efficiency, the degree of near-wellbore damage or stimulation. However, when these data are distorted by afterflow, other methods of analysis are required to extract useful information. One such method involves the use of type curves. Several sets of type curves are available, all of which work well when applied to oil wells and, in many cases, to gas wells. However, all were derived assuming constant fluid properties. For gas wells, this may result in inaccurate values of permeability and flow efficiency, particularly at low pressures when the gas compressibility is large.
This paper presents an extension to gas wells of the "McKinley method" of type-curve analysis for afterflow-dominated data by including the effects of changing gas properties with pressure. While many approximations are involved, it will be demonstrated that, for gas wells, the new curves offer an improvement over McKinley's constant fluid-property curves. There is a penalty to be paid for this improved accuracy, however - the new types curves are more difficult to use than McKinley's. Therefore, they should be used only when (1) pressures beyond the afterflow region are not available for conventional semilog analysis, and (2) improved accuracy is desired relative to what would be obtained using the McKinley (or any constant fluid property) type curves to analyze gas-well buildup data. property) type curves to analyze gas-well buildup data. For rough estimates of damage or stimulation in gas wells, the easier-to-use McKinley curves will be shown to be adequate.
With these new curves, it should be possible to obtain from afterflow-distorted gas-well buildup data a reliable value for near-wellbore permeability, and improved estimates of formation permeability and flow efficiency. This information is valuable in selecting workover and stimulation candidates, as well as in evaluating the effectiveness of workovers, stimulation treatments, and well completions.
Development of the Type Curves Parameters Governing Afterflow Parameters Governing Afterflow When a flowing well is shut in at the surface, there will be a period of time during which appreciable flow into the wellbore will continue. This "afterflow" or "afterproduction" is a result of the wellbore storage capacity, which may be written
F = 5.615 cw V,.............................(1)
where
cw = wellbore fluid compressibility, psi
V = wellbore volume, bbl.
The constant 5.615 converts F to cu ft/psi.
JPT
P. 915
The Interpretation of Reservoir Pressure Data in the Dunbar Field (UKCS)
Authors: Bigno Yann , Baillie J. M. , Coombes T. P. 
Published: December 2007

Summary
The Dunbar field consists of five hydrocarbon accumulations in Jurassic and Triassic sandstones. The existence and extent of dynamic connectivity between these reservoirs as well as lateral and vertical compartmentalization within each accumulation has always been a concern for choosing the optimum reservoir development of Dunbar. Combined with these uncertainties, the existence of downdip permeability deterioration and the near-critical nature of the reservoir fluid complicates the estimation of volumes connected to each well. The benefit of implementing secondary recovery schemes is also greatly dependent on these factors.
This paper presents the role of pressure monitoring as one of the main reservoir management tools for Dunbar and also the different forms of pressure measurements implemented to reduce the uncertainties (e.g., formation pressure tests, extended pressure tests, bottomhole pressure surveys and interference tests). Pressure monitoring, combined with geophysical and geological data [e.g., Strontium isotope residual salt analysis (SrRSA**1) and geochemistry], has played a key role in the early field development.
The Use of Potential Fields in the Search for Potential Fields in the Faroe-Shetland Area
Authors: Morgan Richard , Murphy Colm 
Published: December 2007

Summary
Fundamental geological and environmental differences exist between the basins of the North Sea and the basins of the northwest European continental margin, and strategies for success in the North Sea have not necessarily transferred directly to the continental margin. As a result, exploration outcomes to date have been somewhat disappointing, with one or two notable exceptions.
Furthermore, a change in the approach to acreage evaluation places increasing levels of reliance on seismic data, specifically three-dimensional (3D) data, to tie down prospects before drilling. This approach focuses down rapidly to the prospect scale, and, although allowing detailed analysis of target structures, there is a risk of creating a gap in understanding between the geological processes observed at the basin scale and those at the prospect scale.
A strategy to bridge this gap has drawn upon the wider family of geophysical data, namely gravity and magnetic data, in conjunction with a conventional, broad, regional grid of two-dimensional (2D) seismic data. These data have been worked together to construct a basin scale framework into which 3D seismic data acquisition can be planned and the results interpreted.
At the regional scale, satellite-derived gravity coverage has enabled the removal of the effects of Tertiary seafloor spreading, allowing structures on the northwest European continental margin to be viewed in context with the geology of East Greenland. At the basin scale, basinal elements have been identified and correlated among seismic, gravity, and magnetic data. Controlling faults have been mapped, and the timing of basin formation inferred from trend and geometry, with implications for source rock distribution. At the license block scale, the segmentation of basin margins has been revealed by high spatial resolution magnetic data with implications for both trapping potential and the control of sediment supply into the basins.
The fusion of interpretations made from the different types of geophysical data creates a scale of observation range that stretches from tectonic plates to prospective structures. The resulting geological framework has sufficient scale overlap to relate immediately to the level of detail available from 3D seismic data. Moreover, the broader perspective may ensure that those seismic data are acquired in the correct part of the basin in the first place.
Falcon: A Production Quality Distributed Memory Reservoir Simulator
Authors: Shiralkar G. S. , Stephenson R. E. , Joubert Wayne , Lubeck Olaf , van Bloemen Waanders Bart 
Published: December 2007

Summary
We describe a new production model, Falcon, that has achieved speeds on parallel computers that are 100 times faster on real world problems than current production models on a vector computer. Falcon has been used to conduct the largest, geostatistical reservoir study ever conducted within Amoco. In this paper we discuss the following: Falcon's data parallel paradigm with FORTRAN 90 and high performance FORTRAN (HPF); its single program, multiple data (SPMD) paradigm with message passing; efficient memory management that enables simulation of enormous studies; a numerical formulation that reconciles the generalized compositional approach (based on component masses and pressure) with earlier approaches (based on pressures and saturations), in a more general and more efficient approach. We also discuss Falcon's scalability up to 512 processor nodes and performance (timings and memory) achieved on a number of parallel platforms, including Cray Research's T3D and T3E, SGI's Power Challenge and Origin 2000, Thinking Machines' CM5, and IBM's SP2. Falcon also runs on single processor computers such as PC's and IBM's RS6000. We discuss a new parallel linear solver technology based on a fully parallel scalable implementation of incomplete lower-upper (ILU) preconditioning coupled with a GMRES or Orthomin iteration process. This naturally ordered global ILU preconditioner is scalable to hundreds of processors, efficiently solving the matrix problems arising from large scale simulations
The use of the techniques described in this paper has enabled us to run problem sizes of up to 16.5 million gridblocks. Falcon was used to simulate fifty geostatistically derived realizations of a large, black oil waterflood system. The realizations, each with 2.3 million cells and 1,039 wells, took an average of 4.2 hours to execute on a 128-node CM5 computer, thus enabling the simulation study to finish in less than a month. In this field study, we bypassed upscaling through the use of fine vertical resolution gridding.
Our focus has been on the applicability of Falcon to real world problems. Falcon can be used for modeling both small and very large reservoirs, including reservoirs characterized by geostatistics. It can be used to simulate black oil, gas/water, and dry gas reservoirs. And, a fully compositional feature is being developed.
Linearization Techniques of Reservoir-Simulation Equations: Fully Implicit Cases
Authors: Farkas Éva 
Published: December 2007

Summary
The complexity and nonlinearity of reservoir simulation equations make it possible to apply a great number of linearization techniques. The SPE comparison projects and some other papers compare models for various problem classes. These papers generally compare the results and the speed of runs. The main object of this paper is to examine and compare the models on the basis of the numerical background of the linearization techniques. A general comparison method is proposed that can be applied to analyze these techniques.
Recently, the proposed comparison method has been applied to examine implicit pressure, explicit saturations (IMPES) and implicit pressure, explicit masses (IMPEM) techniques. It has been revealed that the direct IMPES and IMPEM methods result in exactly the same pressure distribution, whereas the saturations and the masses are different. By applying the primary set transformation techniques, the saturation and mass distributions of the direct IMPES and IMPEM techniques can be transformed from one into the other. Now, the fully implicit methods are compared for a three-phase black oil system with one-dimensional (1D) radial grids. The relationships and convergence behavior of the implicit techniques are discussed.
Field Results Demonstrate Enhanced Matrix Acidizing Through Real-Time Monitoring
Authors: Zhu Ding , Hill A. D. 
Published: December 2007

Summary
The use of an inverse injectivity vs. superposition time plot to diagnose the changing skin factor in a matrix acidizing treatment has been presented previously by Hill and Zhu.1 The model has been extended to calculate skin factor as a function of injection time or injected volume to help the operator monitor and optimize the treatment. A Windows program based on the theory has been developed to provide a pretreatment test to evaluate permeability and initial skin factor of the formation when they are not available before the acid treatment, to calculate and plot the evolving skin during the treatment in real time, and to evaluate treatments afterward. It converts surface pressure, when measured, to the bottomhole pressure for the calculation, and handles fluid density and viscosity changes in real time. Several field examples showed that the technique can be used conveniently to monitor skin changes and diversion effects during matrix acidizing treatments. The program is reliable and flexible in acquiring and processing data, calculating skin, and diagnosing matrix acidizing treatments.
A Systematic Experimental Study of Acid Fracture Conductivity
Authors: Beg M. S. , Kunak A. O. , Gong Ming , Zhu Ding , Hill A. D. 
Published: December 2007

Summary
The fracture conductivity created in the acid fracturing process is critical to the success of this stimulation method, but is difficult to predict. We have conducted a series of experiments in which core samples were acidized in a cell that allows for linear flow through a vertical fracture with fluid loss through the cores. The fracture conductivity created was then measured as a function of closure stress. We find that increased acid contact time sometimes results in lower fracture conductivity, fluid loss can increase fracture conductivity, and the Nierode-Kruk correlation1 accurately predicts the effects of rock embedment strength and closure stress on acid fracture conductivity. We also observed that high fracture conductivity is created when the acid forms a deep channel in the fracture.
Making Sense of Water Injection Fractures in the Dan Field
Authors: Ovens J. E. V. , Larsen F. P. , Cowie D. R. 
Published: December 2007

Summary
Water injection above fracture propagation pressure is used to provide improved recovery in the Dan field, a low permeability chalk oil field located offshore Denmark.
Several monitoring techniques have been applied to evaluate fracture height, length, orientation, and injector/producer interaction, including: openhole and through casing saturation logging, tracer injection, producer water cut monitoring, and falloff surveys in injection wells. This paper presents the different monitoring techniques, the development of a fracture growth model, and various examples of the way the model has been used to enhance the understanding of field data.
Modeling of Pressure Buildup on a Kicking Well and Its Practical Application
Authors: Miska S. Z. , Samuel G. R. , Azar J. J. 
Published: December 2007

Summary
We describe a new method for prediction of pore pressure and formation permeability from a kicking well. Getting reliable and accurate information about reservoir parameters (when the formation damage is minimal) is of importance for making proper well completion decisions. In addition, when a well kicks, inaccurate estimation of the formation pressure may cause loss of equipment, possibly the well, and human lives. To combat these problems, a conventional pressure analysis method is modified to predict the formation pore pressure and estimate horizontal and vertical formation permeabilities from a kicking well. The method is simple, and the only prerequisite is that the buildup data be collected upon shutting in a kicking well. Examples with simulated and actual field data are provided to demonstrate the practical application of the method.
Criteria for Backproduction of Drilling Fluids Through Sand-Control Screens
Authors: Marken C. D. , Markestad Per , Rørvik O. H. 
Published: December 2007

Summary
By setting sand-control screens for openhole completions in the same fluid that is used for drilling into the reservoir, considerable cost savings can be realized through the elimination of the need for displacing to a specialized completion fluid. The control of the particle composition of fluids is beneficial in preventing the plugging of the sand-control screens. Conditioning the fluid with fine grade shaker screens for removing the larger fluid particles is sufficient to decrease the amount of screen plugging when back-producing the drilling fluid in the annulus between the screen and formation. Fluids with a lower solids loading are also beneficial for reducing screen plugging. In comparison with direct laboratory evaluations of the screens, particle-size distribution measurements have been found to be insufficient at predicting sand screen plugging.