bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Ultralightweight Spacer for Cementing Jobs Without Nitrogen or Diesel
Authors: Rafael Zepeda G. , Antonio Martínez R. José , Maldonado Reinaldo , José Luis Bustillos G. 
Published: December 2007

Abstract
In the oilfield industry, many resources have been allocated to develop lightweight slurries that will reduce the equivalent hydrostatic pressure against low-pressure formations and achieve successful zonal isolation while performing a cementing job. However, to comply with the standard recommended practices for cementing operations, it is crucial to maintain a progressive rheological and density trend from the spacer up to the tail slurry. Centralization and friction pressure play another very important role in achieving a suitable design and have to be considered during the design stage as well.
This paper describes how a lightweight spacer with 0.88 g/cm3 (7.3 lbm/gal) density was developed and its important contribution while performing a cementing job in a depleted zone.
One of the main contributions is the possibility for decreasing the hydrostatic pressure and the equivalent circulation pressure by increasing the spacer column length. By increasing the column length, additional mud can be returned to the surface, which would represent an important cost savings in cases where the mud is expensive and could be reused.
Not using nitrogen to reduce the hydrostatic pressure also contributes to savings in operational costs and facilitates the job execution and logistics. Eliminating the use of diesel in the spacer to reduce its density minimizes the possibility of having incompatibility and contamination problems with the cement slurry. The reduction of the ecological impact is also an issue to consider.
Finally, we might be able to evaluate features and benefits of this technology as well as its future applications in the industry.
3D Porosity Estimation Using Multiattribute Analysis Methods in One of the Persian Gulf Oil Fields
Authors: Khoshdel H. , Riahi M. A. 
Published: December 2007

Abstract
This study focuses on one of Persian Gulf oil fields. The major reservoir unit in the interested area is composed of alternation of thin dolomite with anhydrite layers. In the available 3D seismic data, these layers are not resolved and generate a composite detectable seismic response, making reservoir characterization difficult through conventional seismic attribute analysis (using single attribute transforms).
In addition to resolving the major reservoir units the main aim of this study is porosity prediction and making 3D porosity cube for detailed reservoir characterization. For this purpose firstly the 3D seismic volume was inverted to obtain an acoustic impedance cube using three different inversion algorithms. Inversion improves the vertical resolution and resolving the interested reservoir layers. Among the different inversion methods applied, according to cross-validation results, acoustic impedance derived from model-based inversion has been selected as the main seismic attribute.
In the next step of this study, acoustic impedance attribute beside other attributes extracted from seismic volume were analyzed using single attribute, multiple attribute regression (with stepwise regression for attribute selection) and neural networks (PNN and MLFN). These linear or non-linear combinations of attribute for porosity prediction result in the improved match between the derived porosity and predicted one.
To estimate the reliability of the derived multi attribute transforms, cross validation is used;
According to results it's found that cross correlation between actual porosity and estimated one has increased from 80% in single attribute prediction to 88% using multiple regression transform. Also neural networks provide higher cross correlation values rather than both. Finally according to cross validation results, multiple regression transform is used for porosity prediction.
Using implemented technique slices prepared which have higher consistency with log data and could lower risk in field development.
A General Unstructured Grid, EOS-Based, Fully-Implicit Thermal Simulator for Complex Reservoir Processes
Authors: Liu K. , Subramanian G. , Dratler D. I. , Lebel J. P. , Yerian J. A. 
Published: December 2007

Abstract
This paper describes a general unstructured grid, EOS-based, fully-implicit thermal simulator for complex reservoir processes. Under the unstructured grid framework, the simulator uses Newton's method to solve component material balance equations, energy balance equation and volume balance equation for component moles, energy and pressure, where chemical reactions and/or external heat sources/sinks are treated in source terms. Because of the similarity among component material balance equations and the energy balance equation, energy is treated as a "component" to achieve a uniform formulation with common code for all simulations (black oil, compositional and thermal).
The thermal simulator was validated using analytical models as well as other thermal simulators. Application of the thermal simulator includes studies of grid-orientation problems and to design and optimise Cold Lake heavy oil development.
Data Management in Reservoir Simulation
Authors: Gencer S. C. , Ketcherside B. P. , Morrell G. O. , Mulkay E. L. , Wiegand K. D. 
Published: December 2007

Abstract
Data from a wide variety of sources are required for reservoir simulation. Simulation itself produces large quantities of data. Yet, good data management practices for reservoir simulation data are typically neither well-understood nor widely investigated. This paper presents a specific architecture to manage reservoir simulation data, discusses experiences from six years of global use, explains adjustments to support changing workflows and outlines challenges that lie ahead.
The architecture consists of a Database Management System (DBMS) and files in managed file directories, called Reservoir Input Output System (RIOS). All simulation input data and results are maintained by a Data Management System (DMS). The reservoir simulator reads input files written from the DBMS to RIOS and writes results to files in RIOS. DBMS, RIOS and integrated management tools (DMS) make up the data management environment.
The environment has been in use inside ExxonMobil since late 2000 and now supports close to 500 users (85% of reservoir engineers). There are over 30 individual databases containing 2TB of online data and about 6TB of online RIOS data. The environment itself introduces some additional work. Support staff is required for maintenance of databases, RIOS areas and problem resolution. Direct user manipulation of data is not permitted and additional tools are required to access and interpret data.
The environment provides many benefits. While it insures data integrity, security and consistency, it also automatically updates defaults, limits, associations, types, etc. This allows running of older simulations and generation of aggregate statistics and usage audit trails.
The architecture and experiences presented in this paper may be unique in the industry. The DMS was designed, developed and deployed over a ten year period. It is a successful software story and is viewed, along with the simulator, as a key enabling technology for success with reservoir simulation within ExxonMobil.
A Compositional Streamline Formulation With Compressibility Effects
Authors: Osako Ichiro , Datta-Gupta Akhil 
Published: December 2007

Abstract
Streamline simulators are gaining increasing acceptance because of their computational advantage, intuitive appeal and ability to visualize the flow patterns in 3D. Much of the current industry experience has been limited to black oil simulation, specifically two phase water-oil displacements under incompressible or slightly compressible conditions. However, given the favorable computational scaling properties of streamline models, the potential advantage for compositional simulation can be even more compelling. Although several papers have discussed compositional streamline formulation, they all suffer from a major limitation, particularly for compressible flow. The decoupling of the compositional pressure and transport equations, which form the basis for streamline simulation, has been accomplished under severely restrictive assumptions.
In this paper, we examine the implications of these assumptions on the accuracy of compositional streamline simulation using a novel and rigorous treatment of compressibility. Our compositional streamline formulation builds on the recent work of Cheng et at.1 and uses the concept of effective density to redefine the bi-streamfunctions and decouple the 3D conservation equations to 1D transport equations for overall compositions along streamlines. The effective density accounts for volume changes with pressure and can be conveniently traced along streamlines. The streamline equations are solved using a third order TVD scheme to minimize numerical dispersion. The phase compositions and saturations are obtained via thermodynamic flash calculations.
We propose a novel ‘optimal’ gridding strategy for efficient solution of the 1D compositional equations along streamlines. The approach is based on a bias-variance trade-off of ‘slowness’ along streamlines and adaptively coarsens the grid for the 1D solution without compromising accuracy. This significantly reduces the number of flash calculations during the 1D solutions. We compare the results from our proposed formulation with finite difference simulation and also, existing compositional streamline formulations in the literature to highlight the importance of the rigorous treatment of compressibility effects. Finally, we examine the scaling behavior of the streamline and finite difference models for compositional simulation to identify potential computational advantages for large-scale field applications.
Efficient History Matching through Production Data Selection
Authors: Liu B. , Kelkar M. G. , Gang T. , Dixon T. N. 
Published: December 2007

Abstract
Reservoir characterization and forecasting require construction of reliable and history matched reservoir models. In gradient-based automatic history matching procedure, most of the CPU time is spent on the sensitivity calculation. When the adjoint algorithm is used to calculate the sensitivity, the CPU time is approximately proportional to the magnitude of observed data. If we can identify observed data with most information content, we can minimize the history matching time using adjoint method and hence make the history matching faster.
A methodology has been developed in this work to identify the important production data and discard those "less useful" data in the automatic history matching procedure. This enables us to save significant computational time without sacrificing much of the history matching result. Our approach ensures that the selected observed data contains little redundancy, and gives similar inverted result based on the contents of all the observed data set.
The method is validated by conducting history matches for synthetic data sets. The comparisons of computational time and the quality of the inverted results indicate that this method is promising and practical for the automatic history matching. Using this approach, computational effort can be reduced by as much as ten times without sacrificing the quality of the results.
Real-Time Microseismic Monitoring of Hydraulic Fracture Treatment: A Tool to Improve Completion and Reservoir Management
Authors: Le Calvez J. H. , Klem R. C. , Bennett L. , Erwemi A. , Craven M. , Palacio J. C. 
Published: December 2007

Abstract
A considerable amount of gas is currently produced from unconventional Mississippian organic-rich shale gas fields such as the Barnett, the Fayetteville or the Bakken formations. Several tight-gas sand formations (e.g., Bossier, Cotton Valley, Lobo, Vicksburg, etc.) also provide valuable resources to be exploited.
These formations are extremely low porosity and permeability reservoirs. They must be effectively and efficiently hydraulically fracture stimulated to produce at commercially economic production rates. Understanding the location and geometry of the created fractures and the area of pay affected by the fracture treatment is key to maximizing the value of the completion and reservoir management program.
Technology has progressed to the point that microseismic monitoring of hydraulic fracture stimulation can efficiently provide extensive diagnostic information on fracture development and geometry. Furthermore, an acquisition system coupled to a real-time processing software linked to a fit-for-purpose visualization package enables true real-time microseismic monitoring of hydraulic fracture treatments.
Firstly, this paper briefly discusses critical elements of a typical microseismic monitoring system including both hardware (e.g., quality of the downhole geophones, coupling to formation) and processing (e.g., velocity modeling, anisotropy).
Secondly, we highlight some of the issues associated with manual picking of microseismic events and discuss an automatic processing technique that enables real-time determination of microseismic event locations.
Thirdly, we discuss the value of real-time microseismic monitoring and the benefits it represents as an additional tool available to the stimulation engineer fracture analysis (e.g., hydraulic fracture containment, stage overlapping).
Small-Scale Fracture Conductivity Created by Modern Acid-Fracture Fluids
Authors: Pournik M. , Zou C. , Nieto Malagon , Melendez M. G. , Zhu D. , Weng X. 
Published: December 2007

Abstract
The effects of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture, both in the main flow direction along the fracture, and in the fluid loss direction. In our tests, the injection rate into the fracture is much higher than in many previous tests, and the fluid loss flux is controlled to match field fluid loss rates. We studied three commonly used acid fracturing fluids—an acid viscosified with polymer, an emulsified acid system, and an acid viscosified with surfactants—at elevated temperatures of 200°F and 275°F. The acid fracture conductivity apparatus is similar to a standard API fracture conductivity cell, but with a capacity to hold core samples that are 3 in. long in the leakoff direction. The long cores allow for better control of leakoff as the acid creates wormholes into the core samples.
In these tests, acid was pumped through the fracture for contact times ranging from 15 to 60 minutes. After the fracture surfaces were carefully characterized with a surface profilometer, the fracture conductivity was measured at increments of closure stress, up to a maximum closure stress of 6,000 psi.
In this paper, we present the results obtained from a series of experiments with these fluids using Indiana limestone and dolomite core samples. Among the findings:
The fracture conductivity created did not show a general increase with acid contact time, and in fact decreased at higher contact times with some fluid systems. This suggests that optimal times of acid exposure in acid fracturing treatments exist.
There were large differences in the conductivity created with the three acid systems tested. At 200°F, the acids viscosified with polymer or surfactants created much higher conductivity than the emulsified acid system.
The laboratory-scale acid fracture conductivities measured in these experiments do not agree with the predictions of the Nierode-Kruk correlation.
Application of a Multidisciplinary Workflow in a Mature Oil Field, Mann Field, Myanmar
Authors: Miskimins J. L. , Graves R. M. , Mu S. L. , Anderson D. S. 
Published: December 2007

Abstract
Mann Field is located in the Salin sub-basin of the central basin of Myanmar (Burma) in Southeast Asia. The field began producing in 1970 predominately from the Oligocene reservoirs. More than 650 wells have been drilled and completed, 106 million stock tank barrels of oil produced, with over 100 million barrels of water injected in an early secondary recovery project. Reservoir management and redevelopment became the focus in 1998. With this redevelopment effort and due to the incredible complexity of the reservoir system (~20 producing intervals in a tectonically active area), the need for a complete multidisciplinary integrated characterization of the field became necessary to maximize economic reserve recovery.
The first step into systematically developing a multidisciplinary workflow is to inventory various data. A significant amount of 3D seismic had been run across the field, likewise core and outcrop information was available. A variety of engineering data including production, injection, drilling, completions, etc, was also available. However, little of the data was integrated into a full reservoir picture and significant amounts were not being used to their full potential.
This paper describes the development of a field management philosophy for a mature (brown) field that incorporates the enormous amount of available data in this field with significant remaining reserves. The company management philosophy includes all areas of development from the utilization of the strong technical staff through the full exploitation of the available data set. The use of outside consulting and training is included to take advantage of technological advancements since the field was originally developed. The need to breakdown the traditional barriers between disciplines is also demonstrated. Building trust, communication, and a working knowledge of all involved disciplines is critical for exploiting Mann Field to its full potential.
Determining Realistic Fracture Conductivity and Understanding Its Impact on Well Performance—Theory and Field Examples
Authors: Palisch Terrence , Duenckel Robert , Bazan Lucas , Heidt Harmon J. , Turk George 
Published: December 2007

Abstract
To hydraulically fracture a well requires large investments in equipment, horsepower, materials and manpower. An engineer can be overwhelmed with the selection of completion fluids, perforation strategy and treatment size, as well as coordination of frac crews. In the end, however, the primary characteristic of the treatment that provides any economic benefit is a conductive fracture that economically increases well production.
Although the primary goal of a hydraulic fracture is to create a highly conductive flowpath, it is often the most poorly understood parameter in the treatment, with pressure transient and rate transient testing frequently indicating disappointingly short fractures of limited conductivity. In order to design an optimized fracture treatment, it is imperative that numerous factors be understood, including proppant embedment, formation spalling, temperature degradation, conductivity loss over time, non-Darcy flow, multiphase flow, non-uniform proppant distribution, cyclic stress, gel damage, fines migration, and other effects.
This paper introduces many of these factors and describes their individual impacts on fluid flow within propped hydraulic fractures. It will also demonstrate the cumulative effect of many of these factors upon fracture conductivity and calculate the corresponding impact on well performance. A fracture treatment optimized to accommodate these damage factors will be shown to differ dramatically from treatments in which these phenomena were ignored.
The authors present field data demonstrating that these effects are not only real, but can substantially impact well productivity. A field study in which the operator intentionally designed fractures to better accommodate these effects will be shown to significantly improve conductivity and fracture half length, as well as production and profitability. Readers of this paper will be armed with a more realistic view of fracture conductivity and fluid flow within propped fractures which, when incorporated into fracture designs, will yield more optimal fracture stimulations, improved production rates, and superior economic returns.
A New Correlation for Relating the Physical Properties of Fracturing Slurries to the Minimum Flow Velocity Required for Transport
Authors: Brannon Harold D. , Wood William D. , Wheeler Richard S. 
Published: December 2007

Abstract
Optimization of effective fracture area is among the principal tenets of fracturing design engineering. It is well understood that effective fracture area is a first order driver for well productivity, and that optimization of effective fracture area is often critical to economic exploitation of reservoir assets. Extensive testing in a large-scale slot apparatus was conducted to evaluate the relative effects of various component and treatment parameters on the proppant transport capability of various slurry compositions. The acquired data were utilized to determine the minimum horizontal slurry velocities necessary for proppant transport using the respective slurry compositions.
An ‘index’ to define the physical properties of a given proppant and fluid composition was defined. An empirical model was then derived to determine the minimum horizontal flow velocity required for suspension transport of a given slurry composition based upon its Slurry Properties Index. The minimum suspension transport velocity may then be compared to the flow velocity profiles from fracture design programs to estimate the propped fracture length likely be observed for those conditions.
Utilizing the new model, the most favorable combination of fracturing slurry component properties and pumping parameters can identified and incorporated in fracturing treatment design and applications to optimize effective propped fracture length, and thereby well performance.
Lessons Learnt from Reservoir Studies on Application of Multilateral Wells
Authors: Jalali Y. 
Published: December 2007

Abstract
This paper is based on a collection of studies, partly published partly unpublished, where the performance of multilateral wells is assessed from the viewpoint of reservoir drainage. The underlying studies range from case study of multilateral wells with production history, to feasibility studies of multilateral wells (in land, platform, and subsea fields), to generic studies by numerical methods and optimization techniques on reservoir drainage efficiency of multilateral wells. This paper will not reproduce a full account of those studies, rather it will highlight the key lessons latent in those studies which may serve as useful guiding principles for those contemplating or planning use of such wells. Specifically, the paper addresses how multilateral wells fare against the more conventional or traditional horizontal wells. The key concepts are summarized in four ‘lessons’ pertaining to high-drawdown, low-drawdown, multi-reservoir, and injection applications. Brief mention is made also of aspects other than reservoir drainage (or injection) efficiency that can influence the choice of well architecture.
Avoiding Pitfalls When Upscaling Core Data
Authors: Kennaird T. 
Published: December 2007

Abstract
Core data being considered for upscaling must be evaluated to determine they are reservoir representative.
Some key considerations:
Is the core vertically and laterally representative? Did anything happen to the core during retrieval or subsequent handling which may have caused unrepresentative data to be acquired? Was the core sampled to honour lithological heterogeneity? Were the core analysis methods compatible with petrophysical properties? Did the core analysis method represent not only reservoir conditions such as net overburden pressure, but also such parameters as the anticipated production mechanism?
Core data should be thoroughly screened in this manner to ensure their suitability for upscaling. At this point, the upscaling method must then be judiciciouly considered.
Practical examples illustrating the above points are given throughout the paper.