bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving the Simulation of Waterflood Performance With the Use of Neural Networks
Authors: Aminian K. , Bilgesu H. I. , Ameri S. , Gil E. 
Published: December 2007

Abstract
Secondary recovery performance of most oil reservoirs is impacted by formation heterogeneity. Therefore, accurate description of the formation attributes is necessary for appraising the economic success of the secondary recovery operations in a complex reservoir. Porosity and permeability distributions are the key formation attributes, which are required for realistic simulation of the secondary recovery performance. The permeability and porosity are usually determined from the analysis of the core samples. Generally, core samples are only available from limited number of wells in the reservoir because of the expenses associated with obtaining and analyzing the core samples. At the same time, geophysical logs are commonly run in most of the wells in the reservoir. Well log data are then utilized to identify the productive intervals and to estimate the formation porosity. A correlation between core-derived permeability and log-derived porosity is often developed and utilized for permeability prediction. However, a reliable correlation between permeability and porosity generally cannot be established in heterogeneous formations. This is mainly due to presence of multiple "Flow Units" within the formation. The Flow Unit is defined according to geological and petrophysical properties that influence the flow of fluids. Prediction of Flow Units is a difficult and complex problem because typically the available information from cores is inadequate. The use of well log data to identify the Flow Units and predict permeability distribution therefore, represent a significant technical as well as economic advantage. In this study, several artificial neural networks were successfully developed to predict the Flow Units, permeability and porosity from the available well log data. The study was performed in an oil filed located in West Virginia. Well log data and core analysis results from seven wells in this field were utilized to train and test the neural networks. The results of the networks’ prediction in conjunction with the relevant secondary recovery data were then utilized to simulate the secondary recovery performance. The simulation results indicated that the neural network predications significantly improved the simulation of the secondary recovery performance.
Parallel Computing Techniques for Large-Scale Reservoir Simulation of Multi-Component and Multiphase Fluid Flow
Authors: Zhang K. , Wu Y. S. , Ding C. , Pruess K. , Elmroth E. 
Published: December 2007

Abstract
Massively parallel computing techniques can overcome limitations of problem size and space resolution for reservoir simulation on single-processor machine. This paper reports on our work to parallelize a widely used numerical simulator, known as TOUGH2, for nonisothermal flows of multi-component, multiphase fluids in three-dimensional porous and fractured media. We have implemented the TOUGH2 package on a Cray T3E-900, a distributed-memory massively parallel computer with 695 processors. For the simulation of large-scale multicomponent, multiphase fluid flow, the requirements for computer memory and computing time are extensive. Because of the limitation of computer memory in each PE (processing element), we distribute not only computing time but also the memory requirement to different PEs. In this study, the METIS software package for partitioning unstructured graph and meshes is adopted for domain partitioning, and the Aztec linear solver package is used for solving linear equation systems. The efficiency of the code is investigated through the modeling of a three-dimensional variably saturated flow problem, which involves more than one million gridblocks. The execution time and speedup are evaluated through comparing the performance of different numbers of processors. The results indicate that the parallel code can significantly improve capacity and efficiency for large-scale simulations.
Reduce the Number of Components for Compositional Reservoir Simulation
Authors: Liu Kai 
Published: December 2007

Abstract
The need to predict reservoir fluid compositional changes under varying pressures and depletion processes arises because the hydrocarbon recovery of some types of reservoirs is strongly composition-dependent. Since hydrocarbon component material balance equations must be solved in compositional reservoir simulation, both computer memory requirements and simulation run time are greatly increased.
This paper presents a series of technologies, including a Fully Automatic Regression Technique, a Best Lumping Scheme, and a Fully Automatic Reservoir Fluid Characterization procedure, to reduce the number of components needed to characterize a reservoir fluid using an Equation of State (EOS). As a result, the compositional reservoir simulation run time can be greatly reduced without reducing the required accuracy of the match with available laboratory data. Applications indicate that a significant speedup has been achieved using fewer components to model the reservoir production processes while the predicted reservoir performance is equivalent to that achieved using many more components.
Thermal Simulation with Multisegment Wells
Authors: Stone T. W. , Bennett J. , Law D. H. -S. , Holmes J. A. 
Published: December 2007

Abstract
The extension of a previously reported well model to compositional and thermal applications is discussed. This multisegment, multi-branching wellbore model has been fully coupled to a commercial reservoir simulator which can operate in black-oil, compositional or thermal modes. In this paper, the discussion will focus on thermal, heavy oil applications where simulation requires a better representation of the wellbore geometry and the physics of fluid flow and heat transfer.
Cupiagua: A Complex Full-Field Fractured Reservoir Study Using Compositional Upscaling
Authors: Ballin P. R. , Clifford P. J. , Christie M. A. 
Published: December 2007

Abstract
The first application of compositional upscaling to the routine modeling of a major reservoir is described. The reservoir, Cupiagua in Colombia, is a rich gas condensate field. Given that Cupiagua falls rapidly below dewpoint, and produced gas is recycled, the main recovery process is the vaporization of liquid components into the gas phase, and transport of these components in the gas phase to production wells. Therefore the process is compositional but flow is dominantly in 1 phase.
Cupiagua is a heterogeneous reservoir, in which the main heterogeneity consists of natural fracture corridors, accounting for more than 80% of the permeability in some areas. It is not possible to represent these features explicitly within the full field model (FFM), nor do they fit a conventional dual porosity representation. Therefore an upscaling process is required.
The process described in this paper is the use of alpha factor compositional upscaling functions, which modify the velocities of individual pseudo-components. Alpha factors are now incorporated into the Cupiagua FFM and are in daily use for all modeling applications in this major field.
Insights into Upscaling Using 3D Streamlines
Authors: Chawathé Adwait , Taggart Ian 
Published: December 2007

Abstract
Large multi-million cell geological models are frequently constructed in an effort to "capture" the vertical heterogeneity measured by well logs and the areal heterogeneity inferred by the depositional environments. These criteria often result in fine scale models at a resolution of 0.1-0.3 m vertically and 30-100 m areally, resulting in reservoir models to the order of 107 grid cells. Recourse is made to upscaling in order to obtain coarsened but computationally efficient flow simulation models. The coarsened models commonly result in no more than 1-5% of the original grid size underscoring the need for judicious upscaling. Of greater importance is to demonstrate, for the chosen grid dimensions, that the upscaled representation is both reasonable and optimal in the sense that a significantly better template would be difficult to obtain.
We consider two non-uniformly coarsened models to demonstrate the issues involved, and show that the use of 3D streamline methods offers insightful alternatives to decoupled analysis for both, the scale-up template design and pre- and post-diagnostics. We confine ourselves to property upscaling methods that use local grid information as opposed to estimating upscaled properties based on some global measure. For this class of problems we demonstrate that the diagnostic phases are necessarily separate from the upgridding and upscaling processes.
Re-Engineering the Well Calibration Procedure for a Large Number of High Productivity Wells
Authors: Siu Alan L. , Al-Khatib Mohammed H. 
Published: December 2007

Abstract
Well calibration after a history match in reservoir simulation ensures that the production wells will give realistic rates during the prediction phase. This process is usually very time consuming. The amount of trial-and-error work increases dramatically as the number of wells and/or the well productivity indices increase. In addition, reservoir simulation models are getting bigger and may contain a greater number of wells as computer hardware expands its limits. A reservoir model with hundreds of high productivity wells would take months to calibrate using conventional approaches. This paper describes a systematic well calibration procedure that yields very high degree of accuracy and requires only a fraction of the usual time. It was demonstrated that, with simple planning in the application of the PFV calibration process, a reservoir model with 500 high productivity wells could be calibrated within a couple days after obtaining a successful history match. The PFV procedure is general and it can be applied to any reservoir simulators.
Coupling Reservoir Simulation Technology with the Internet to Provide Realtime Reservoir Management
Authors: Barden Dick , Smith Chuck , Schubarth Stephen 
Published: December 2007

Abstract
By combining the internet with the latest in reservoir simulation technology, it is now both possible and feasible to direct oil and gas field development in near real-time, using a continuously updated computer model that matches and reflects the actual rate and pressure data observed in the field. While monthly updates are probably sufficient in most cases, operators have the option of updating weekly, daily or even more frequently in order to meet the needs of each situation. This ground breaking approach removes much of the risk from the evaluation of well completions, optimizing the location of offset and infill wells, predicting reservoir pressures, wellhead pressures, flow rates and reservoir drainage patterns, identifying the most effective completion methods, well spacing patterns and many other field management decisions.
This paper discusses how such dynamic reservoir simulation and management can be implemented, even for small, remote production locations. It also cites examples of where this has already been tried, the results that were obtained and describes the experience of those who have actually implemented this approach.
This new methodology, which currently addresses most types of depletion drive and waterflood operations, is of considerable importance to the industry, not only because of the enormous impact it can have on any individual operation, but also because of the paradigm shift that it will bring about as the process gains acknowledgement in the main stream. The capability now exists for operators, regardless of their size or location, to model every new development well (prior to drilling), identify the most cost-efficient reservoir drainage plan and to adjust that plan in an ongoing manner based on actual field/well behavior.
Optimization Methods for History Matching of Complex Reservoirs
Authors: Schulze-Riegert R. W. , Axmann J. K. , Haase O. , Rian D. T. , You Y. -L. 
Published: December 2007

Abstract
Conventional direct optimization methods and Evolutionary Algorithms are applied to the problem of history matching in reservoir engineering. For the optimization of complex reservoir models the potential of parallel computing is investigated. Methods to improve the convergence of Evolutionary Algorithms by introducing expert knowledge is discussed.
An interface program has been developed which links an industry standard reservoir simulator to an optimization software package designed as a multipurpose environment for parallel optimization. Permeabilities, fault transmissibilities as well as relative permeabilites and barrier locations have been included in the optimization.
Results are presented for synthetic and real reservoirs with up to 30 wells and 40 design parameters. The potential and the area of applicability of the optimization method to the problem of reservoir modeling in various modeling phases are discussed. The improvement of performance based on parallelism in a network environment is evaluated.
In conclusion, results suggest that Evolution Strategies can be successfully applied for generating possible solutions in the early modeling phase. The introduction of expert knowledge to the optimization methods is essential for reducing the multidimensional search space and improving convergence.
Calibration of Fractured Reservoirs with Dynamic Data
Authors: Verga F. M. , Giglio G. , Masserano F. , Ruvo L. 
Published: December 2007

Abstract
Fractured reservoirs are reservoirs whose productivity and performance are controlled or strongly affected by the fracture network occurring in the field. Therefore, a correct characterization of the reservoir internal geometry and a suitable description of the effective fracture network are crucial for a predictive model to be reliably applied to performance prediction and production forecast. A new approach has been attempted to validate the reconstructed internal geometry of a selected fractured reservoir by reproducing the dynamic behavior of the reservoir monitored during MDT tests. The description of the reservoir fracture network was achieved by integration of relevant data that could be collected from wireline logs, especially imaging and sonic logs, conventional cores, specifically aimed at microfracture examination, small drilling mud loss analysis, and field scale observations of regional structural heterogeneities from outcrop analogs inspection. Fracture types, distribution, geometry, properties, interaction with matrix, and deformation history were thus defined. Fracture patterns were described in terms of distributions for orientation, size, shape, spatial location and intensity to stochastically generate a static model of the fractured reservoir. The dynamic behavior of the fractured system was reproduced by a finite element flow model able to simulate transient flow through three-dimensional rock masses with discrete fracture networks. Consistency was required between the observed and simulated pressure data also in terms of derivative pressure trend to assure that the reservoir geometry was adequately modeled. Analysis of the model response as a function of the assigned fracture parameters and comparison between the observed and simulated dynamic behavior allowed calibration of the fracture modeling parameters and achievement of a satisfactory description of the reservoir effective fracture network.
Hydraulic Characterization of Fractured Reservoirs: Simulation on Discrete Fracture Models
Authors: Sarda S. , Jeannin L. , Bourbiaux B. 
Published: December 2007

Abstract
Advanced characterization methodology and software are now able to provide realistic pictures of fracture networks. However these pictures have to be validated against dynamic data like flowmeter, well test, interference test or production data and calibrated in terms of hydraulic properties. This calibration and validation step is based on the simulation of these dynamic tests. What has to be overcome is the possibility to both accurately represent large and complex fracture networks and simulate matrix-fracture exchanges with a minimum number of grid-blocks. This paper presents an efficient patented solution to tackle this problem. First, a method derived from the well-known dual-porosity concept is presented. The approach consists in developing an optimized explicit representation of the fractured medium and specific treatments of matrix-fracture exchanges and matrix-matrix flows. In this approach, matrix blocks of different volumes and shapes are associated to each fracture cell depending on the local geometry of the surrounding fractures. The matrix block geometry is determined using a rapid image processing algorithm. The great advantage of this approach is to simulate local matrix-fracture exchanges on large fractured medium in a much faster and appropriate way. Indeed, the simulation can be carried out using a much smaller number of cells compared to a fully explicit discretization of both matrix and fracture media. The proposed approach presents other advantages due to its great flexibility. Indeed, it accurately handles the cases where flows are not controlled by fractures alone: either the fracture network may be not hydraulically connected from one well to another, or the matrix may have a high permeability in some places. Finally, well test cases demonstrate the reliability of the method and its range of application.
Reduction of Synthetic Based Fluid Discharges Offshore by the Use of Vertical Basket Centrifuges
Authors: Cannon R. W. , Martin Dale 
Published: December 2007

Abstract
Currently many operators are making a concentrated effort to reduce the amount of synthetic based drilling fluids or muds (SBM) discharged offshore. In order to achieve these goals many new devices are being developed such as the vertical basket centrifuge. Vertical basket centrifuges have been used in the mining industries for years to dry water-wet coal and other processed minerals. These centrifuges have proven successful in the reduction of synthetic based drilling fluid on cuttings (SOC) for drilling operations worldwide (Fig. 1).
This paper will describe the typical cuttings drying equipment suite, layout, and performance of the vertical basket centrifuge. The SBM recovery package involves a two part process: a vertical basket centrifuge for drying of the SBM drill cuttings and the use of a high speed decanting centrifuge for reconditioning and re-use of the recovered SBM drilling fluid.
In most instances the rig's shale shakers are unable to consistently produce dry drill cuttings in relation to the amount of synthetic on cuttings (SOC). Field data has shown as much as 50 to 70 percent reductions in the percent by weight SOC between shale shakers and vertical basket centrifuges samples, thereby effectively reducing the amount of synthetic-based drilling fluid that would have otherwise been discharged overboard.
Engineering Training Needs for the New Millennium
Authors: Wilke J. G. , Hoskins R. C. 
Published: December 2007

Abstract
The roles service company engineers play in the oil and gas industry have changed drastically over the last decade. Prior to 1990, the engineering staff employed by the operating company did most reservoir and production history analysis. The last decade has seen this situation change. During the 90's, while seeking to streamline their own operations, many operating companies began to depend much more heavily upon service company engineers to do the background work described above. Working relationships evolved to the point that service company engineers are often stationed at the operating companies' facilities while performing duties that had previously been the responsibility of the operating companies' reservoir or production engineering departments. This creates an atmosphere of increased service company accountability. Directly proportional to this increase in accountability is the degree of service company engineer responsibility. No longer does the service company engineer simply design treatments based upon the request of the customer.
To meet these demands, service companies have had to implement training programs that equip their engineering staffs with the tools to perform these new job responsibilities, including reservoir, drilling and completions engineering functions. This paper will describe a grid curriculum structure developed to meet the needs of pressure pumping service company engineers. A vast array of classes, some of which were never before available to service company engineers from within, have been viewed as essential to the success of the operating/service company partnerships.
As we move into the next millennium, the curriculum structure must be flexible enough to meet the ever-changing needs of the industry. How will these individuals' roles change over the next decade? No one knows for sure. If the changes are as profound as the last decade, the training program's scope and flexibility are crucial for its future success.
Seismic Determination of Saturation in Fractured Reservoirs
Authors: Brown R. L. , Wiggins M. , Gupta A. 
Published: December 2007

Abstract
The determination of reservoir saturation using the seismic response is an important element of predicting the performance of fractured reservoirs. One of the primary saturation problems the seismic signal can address is the location of the gas cap with respect to the water or oil leg. The classical Gassmann (1951) approach to predicting the effects of saturation upon the seismic signal is not valid for fractured reservoirs. Instead, the results of Brown and Korringa (1975) that account for the anisotropy of the dry rock are used to predict the effects of saturation upon the seismic signals. For a single set of vertical, aligned fractures the P-waves are most sensitive to the saturation when they are nearly perpendicular to the fractures. For S-waves, a classical result is obtained: the S-waves are not sensitive to the saturation within the vertically aligned fractures. However, when the elastic symmetry of the dry rock differs from the case of vertical fractures, the S-waves become sensitive to the saturation. This can happen when either the fractures are tilted slightly away from the vertical or when the fractures are best described as rough surfaces. In these cases, S-waves are most sensitive to the saturation when propagating parallel to the cracks with a polarity perpendicular to the cracks. These results indicate that an S-wave "bright spot" or region of increased S-wave splitting can be used to predict gas versus brine or oil-saturated portions of the reservoir. Since P-waves have the maximum sensitivity to the saturation of a fractured reservoir when they propagate perpendicular to the fractures, they require long-offset surface seismic methods that may be difficult to implement in practice. However, since vertically propagating S-waves with different polarizations can be used
to study the effects of the saturation, they offer the most potential for mapping saturation within fractured reservoirs.