bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sucker-Rod-Pumping Failures in the Permian Basin
Authors: Heinze L. R. , Ge Z. , Rahman M. M. 
Published: December 2007

Abstract
Sucker rod pumping is the most popular form of artificial lift in the Permian Basin, which is one of the largest petroleum production basins in the United States.This paper is part of the research results of the Artificial Lift Energy Optimization Consortium (ALEOC),a research project which is sponsored by 11 oil companies operating in the Permian Basin.The analyzed data provided by these 11 oil companies came from more the 25,000 sucker rod pumping wells, a quarter of the total sucker rod pumped wells.The wells' locations are scattered in the Permian Basin. Therefore the information presented here is typical enough of this area. This paper presented the methods used to organize and pre-treat the primary databases provided by the operators, and the techniques used to analyze the failure data. Failure frequency was introduced to do comparisons, plots according to failure frequency, year, company, area location, and formation were given to make the data more straightforward. Analysis of results show that different companies have very different operation management and data manipulation methods, which made it necessary for companies to come together to learn from each other. There are big differences among the failure frequencies of companies, which is an indicator of their field operation efficiency, facility manipulation underground working conditions of the sucker rod pumping equipment and so forth. There is a trend of yearly failure frequency decrease among the participated companies with a few exceptions; pump failure frequency is the largest problem among those of the sucker rod pumping components. The results present a picture of sucker rod pumping in the Permian Basin and can be used in further statistical analysis of the sucker rod pumping failures and to guide later decision-making.
Coiled Tubing Used as a Continuous Sucker-Rod System in Slim Holes: Successful Field Experience
Authors: Solanet Fernando , Paz Luis , Leniek Humberto 
Published: December 2007

Abstract
The need of cutting the costs of new oil wells in the San Jorge Basin led YPF S.A. to study the option of reducing well diameters. For an effective cost reduction, it was necessary to be able to case the hole with diameters smaller than 4.5 inches.The problem of a completion in 3.5 inches or less was the inability to efficiently lift the production with traditional methods.Initially a monobore type completion was tested, in detriment of pump setting depth and pump efficiency due to the presence of gas.
The introduction of a mechanical pumping system lifting fluids through coiled tubing made possible the solution of the problems of the pump depth and efficiency. The paper describes the type of installation and procedure followed to run the system.
The success of this type of installation will allow the operator to produce in wells cased with 3.5 inches or less, matching the efficiency of conventional wells cased with 5.5 inches, in a range of production volumes compatible with most of the wells in the basin. At the same time, the system offers the advantage of using conventional technology such as beam pump on the surface and mechanical pump at the bottom of the well.
Conditioning 3D Stochastic Channels to Pressure Data
Authors: Bi Zhuoxin , Oliver D. S. , Reynolds A. C. 
Published: December 2007

Abstract
This work discusses the development and implementation of a procedure to condition a stochastic channel to well- test pressure data and well observations of the channel thickness and the depth of the top of the channel. The stochastic channel is defined by a set of geometric random variables (referred to as geometric model parameters) that describe the location, size and shape. Channel and non- channel permeability and porosity are treated as random variables. These four random variables plus the geomet- ric parameters comprise the complete set of model param- eters. Multiple conditional realizations of the geometric parameters and rock properties are generated to evaluate the uncertainty in model parameters and the reduction in uncertainty obtained by conditioning to well-test pressure data.
Analytical Solutions for Productivity Evaluation of Multifractured Wells in Multilayered and Bounded Reservoirs
Authors: Basquet R. , Alabert F. , Caltagirone J -P. 
Published: December 2007

Abstract
We propose a semi-analytical model to represent the transient and pseudo-steady state behavior of hydraulic fractures in multilayered reservoirs where cross-flow is permitted between layers. Fractures can be horizontal or vertical. We only consider vertical fractures which are parallel to x or y axes. Fractures are fully or partially penetrating in the formation and can extend across several layers. We consider single or multiple fractures where influence between each other is modeled. The reservoir is bounded by plane surface perpendicular to the main axes, and we can impose on these limits either no-flow, constant pressure or mixed boundary conditions.
The solutions are obtained from plane (zero thickness) source solutions developed in the Laplace-Fourier domain. Basquet et al.1 already used this method for the determination of point source solutions, the reasoning is still based on the « quadripole » method to account for layer cross-flow and on the Fourier transform to describe boundary effects. Vertical line source solutions are developed and are then integrated over the horizontal fracture extension to obtain the plane source solution under the assumption of uniform flux solution. The infinite conductivity solution is obtained by splitting the fractures into basic slabs with uniform flux and solving a linear system.
The solution is validated against existing analytical solutions (using concept of instantaneous sources and Green's functions) modeling vertical or horizontal fractures in single layer reservoir. To check that the cross-flow between layers is well represented, we compared our vertical line source transient solution versus well known analytical solutions in multilayered reservoirs.
Innovations in Global Electronic Data Delivery
Authors: Murchie S. , Provost J. T. , Burke T. , Karr G. , Alam S. O. , Scheibner D. , Citerne A. 
Published: December 2007

Abstract
New techniques and technologies have been developed and assembled to create a global electronic data delivery framework that is robust, secure and efficient. This framework serves any data type throughout its life span—as it is acquired, processed and archived—and provides the means for it to be transmitted and intrinsically integrated into the end user's domain. Details of the data delivery framework and its overall scope will be given, followed by a number of geographically distinct, tailored applications of the technology.
The advancing technology front has resulted in an explosion in data volume, of which an ever-increasing amount is digital. In the midst of this explosion, the need for the highest quality data to be efficiently and electronically delivered to its various destinations has remained a goal. The solution presented herein combines an enhanced mechanism for electronic data delivery with tools that improve data usability, storage and management. All the while the data adhere to the exploration and production (E&P) standards.
This framework is being applied today to formation evaluation data, such as wireline and logging-while-drilling data. However, it will soon expand to encompass all forms of data produced within the E&P industry. As the industry rapidly assimilates advances in electronic communications to improve operations efficiency, its decision-makers are demanding drilling and formation evaluation data on their desktops in real time.
This paper outlines significant contributions in the areas of data security and transmission reliability, capitalizing on established and expanding networks (Internet, intranet), data composition and management techniques, and the development of software applications to facilitate end-user data reception, handling and manipulation.
Reducing Uncertainties in Production Forecasts by Constraining Geological Modeling to Dynamic Data
Authors: Hu L. Y. , Le Ravalec M. , Blanc G. , Roggero F. , Noetinger B. , Haas A. , Corre B. 
Published: December 2007

Abstract
Building reservoir geological models that are consistent with all available information is necessary to reduce uncertainties in production forecasts. The stochastic/geostatistical approach is the only feasible way of integrating all kinds of data ranging from the geological knowledge to the production history. A stochastic model is chosen that accounts for geological knowledge, and geostatistical simulation provides realizations of the stochastic model. These realizations can be conditioned to static data at well locations to reduce the model uncertainty in the area where data are available.
All along the different stages of a field life more and more dynamic data are available. This paper addresses the issue of generating model realizations that account for available dynamic data to further reduce uncertainty in the underlying geological model. A general tool has been developed to build geostatistical realizations that match both the available geological and dynamic data. The core of this tool is the Gradual Deformation Method that allows consistent modification of a realization in a continuous way. This method can be combined with a nonlinear optimization method for constraining realizations of a stochastic model to dynamic data. This approach is operational for Gaussian or non- Gaussian pixel based models. Model realizations can be deformed globally or locally while preserving the geostatistical characteristics. Several examples are provided to illustrate different features of the gradual deformation approach.
Extrapolation of Laboratory Measured Black Oil and Solution Gas Fluid Properties for Variable Bubblepoint Simulation
Authors: McCain W. D. , Spivey J. P. 
Published: December 2007

Abstract
Reservoir simulation of variable bubblepoint processes such as water or gas injection into black oil reservoirs often requires extrapolation of reservoir fluid properties to pressures above original bubblepoint pressure. This has been known for over twenty years; however, to date, no rational and consistent procedure for these extrapolations has been proposed.
We propose a scheme to extrapolate solution gas-oil ratios and the corresponding oil formation volume factors, oil viscosities, and oil densities, which preserves the correct relationship of these properties to pressure. The procedure is based on empirical observation that the relationship between solution gas-oil ratio and oil formation volume factor is linear and that oil viscosity and oil density have a linear relationship in the pressure range of interest. A material balance equation is used to connect the quantities and properties of the surface fluids, oil formation volume factor, and solution gas-oil ratio to the density of the reservoir oil. Thus, the four properties can be extrapolated together in an empirically and theoretically based process.
A similar scheme is used to extrapolate the properties of the solution gas, forcing the correct shapes of gas z-factor, gas formation volume factor, and gas density as functions of pressure. Gas viscosity, as usual, is calculated with a correlation.
After extrapolation, the consistencies of these oil and gas properties are checked by ensuring that total compressibility remains positive throughout the range of extrapolated pressure. Thus, a rational procedure based on known empirical and theoretical relationships among these fluid properties is now available for use in preparing fluid properties for reservoir simulation when the possibility of variable bubblepoints exists.
The application of these relationships to quickly extrapolate values of these seven fluid properties is demonstrated using an interactive graphical spreadsheet.
An Efficient Finite Difference Model For Flow In a Reservoir With Multiple Length-Scale Fractures
Authors: Lee S. H. , Jensen C. L. , Lough M. F. 
Published: December 2007

AbstractWe describe a hierarchical approach for modeling fluid flow in a naturally fractured reservoir with multiple length-scale fractures. Based on fracture length (lf) relative to the finite-difference grid size (lg), fractures are classified as belonging to one of three groups: (1) short disconnected fractures (lf &lt;&lt; lg), (2) medium-length fractures (lf ~ lg), and (3) long fractures (lf &lt;&lt; lg). Effective grid-block permeabilities, associated with the short and medium length fractures, are used as input to a finite-difference simulator. We also present a separate transport equation for flow through long fractures to capture effects of large-scale high permeability pathways. Our new approach provides an improved means to include realistic and explicit fracture descriptions.Previously, Lough et al. (1997, 1998) developed a numerical method to compute the effective permeability of simulation grid-blocks with realistic fracture characterizations. Although this method handles generalized fracture geometries, it is numerically inefficient for the case where many small fractures exist. The method can also underestimate the flow contribution from long fractures. Assuming a linear potential gradient alongthe short fractures, we derive an analytical solution for the permeability contribution from short fractures. The solution becomes more accurate as fractures become randomly distributed and asymptotically small in length. The permeabilities from this analytical solution are used as the effective matrix permeability in computing a combined effective grid-block permeability that includes medium-length fractures. The method of Lough is used for this computation. This hierarchical approach takes into account coupled flow between the rock matrix, short fractures and medium-length fractures. Long fractures are modeled explicitly in the reservoir simulator, using a transport equation that describes flow between long fractures and surrounding simulation grid-blocks.Simulation results from our new hierarchical approach are compared with those from the conventional dual porosity/permeability model. Numerical efficiency and accuracy are also examined.
Application of a New Model to Analyze Leakoff Tests
Authors: Altun G. , Langlinais J. , Bourgoyne A. T. 
Published: December 2007

Abstract
A leak-off test (LOT), commonly known as formation pressure integrity test (PIT), is a verification method to estimate the fracture pressure of exposed formations. After cementing each casing string, a LOT is run to verify that the casing seat can withstand the wellbore pressure required to safely drill to the next casing setting depth. Fracture pressure determined from the test is used as the maximum pressure that may be imposed on that formation. Critical drilling decisions for subsequent casing setting depths are based upon the result of a LOT. Accurate formation fracture gradient determination is critically important.
Although a LOT is a simple and inexpensive test, its interpretation is not always easy, particularly in formations that give non-linear relationships between the pumped volume and the observed pump pressure. Ideally, a straight-line relationship of pump pressure to volume pumped is obtained that reflects primarily the total system compressibility, i.e., the compressibility of the drilling fluid, casing expansion, and wellbore expansion. Non-linear LOT behavior is thought to be caused by gas in the system, by borehole failure, or by leakage of drilling fluid into the cemented casing/borehole annulus. There is, however, no mathematical model explaining the non-linear LOT behavior. Disagreement on determining or interpreting actual leak-off pressure from the test data among the operators is common, especially for shallow formations.
In this study, a mathematical model is derived to assist in the analysis of non-linear LOT behavior. The model has been used to predict the observed non-linear behavior of field examples. In the case of a non-linear LOT, the model has also been used to predict the maximum fracture pressure of the formation without running a test until formation fracture.
Low Field NMR-Tool for Bitumen Sands Characterization: A New Approach
Authors: Mirotchnik K. D. , Allsopp K. , Kantzas A. , Curwen D. , Badry R. 
Published: December 2007

Abstract
NMR well logging technology has become a recognised and effective method for characterising hydrocarbons in porous media. Many recent publications have attested to its suitability for this purpose. NMR can be used to determine porosity, permeability and viscosity in situ, to estimate pore size distribution, to indicate wettability alteration during the recovery process and to determine many other important parameters. All previous NMR applications were developed for investigating conventional oil reservoirs. Extending the detection capabilities of NMR Logging tools into heavy oil and bitumen reservoirs for in situ characterisation is very important for oil producers in the Province of Alberta, Canada and other heavy oil and bitumen areas (Venezuela, California, Russia, etc.). The main problem encountered when trying to use NMR technology to evaluate these reservoirs is that the relaxation characteristics of heavy oils and bitumen are at the limits of the logging tools’ detection capabilities.
The NMR signal obtained from conventional oil, heavy oil and bitumen formations can consist of both hydrocarbon signal and water signal. Each NMR signal can further characterise both mobile and immobile fluids in the porous media. However, as the viscosity of the hydrocarbon phase increases and the NMR signal shifts towards lower relaxation times, the composite NMR signal for the hydrocarbon bearing formation becomes very complicated. As the viscosity of the bitumen exceeds 100,000 cP (at natural conditions), the relaxation characteristics of bitumen become partially non-detectable by both the logging and laboratory NMR tools. As a result, the conventional methods of NMR detection fail to recognise precisely the hydrocarbon components.
Laboratory NMR measurements of bitumen bearing porous media under different temperatures were performed. This method delivered new information about bitumen reserves in situ. The results show that low field NMR holds promise for the characterisation of heavy oil and bitumen recoverable reserves. This new approach can be applicable for real time monitoring of thermal extraction including monitoring the efficiency of thermal recovery methods.
Waxy Crude Oil Restart: Mechanical Properties of Gelled Oils
Authors: Hénaut I. , Vincké O. , Brucy F. 
Published: December 2007

Abstract
In case of a prolonged shutdown and an inopportune cooling, the crystallization of a crude oil takes place and hinders the production of these petroleum products. Because of the gel-like network formed by the crystals entrapping the oil, a restarting pressure is required to start-up flow. In order to predict the necessary pressure, the restart process and the corresponding mechanical behavior of the gelled oil must be assessed. In this paper, a set of two experimental approaches is presented and discussed in relationship with the restart process. The solid-like behavior of the gelled bulk oil was investigated thanks to a set of mechanical test cells. The rheological behavior of the gelled waxy crude oil was studied with a vane test apparatus and a controlled-stress rheometer. Eventually, the two experimental methods gave complementary and converging results revealing how a crude oil stuck inside a pipeline would react during a restarting operation. They help the understanding of the physical mechanism of the flow restart and release the data required for prediction.
An Evaluation of Simulation Techniques for Modelling Squeeze Treatments
Authors: Mackay E. J. , Sorbie K. S. 
Published: December 2007

Abstract
Modelling scale inhibitor squeeze treatments is taking on an expanding role, partially due to the increasing complexity of systems that need to be treated against scale formation, and partially due to the improved accessibility of codes capable of modelling these treatments. Five such codes have been identified, ranging from near wellbore single-phase models designed with inhibitor squeeze treatments specifically in mind, to full field, fluid, thermal and chemical transport simulators. The former type of model is routinely used by production engineers to optimise squeeze treatments. The later is a tool that can be used in a research environment for improved understanding of various aspects of squeeze application, or to study specific cases that are exceptionally problematic. The risks associated with horizontal wells in particular, partly due to their cost, and partly due to the potential losses from deferred oil, mean that modelling is often seen as a useful tool in reducing uncertainties.
The choice has to be made between the requirement for accurate flow calculations and chemical modelling, and the need to set up models quickly and accurately. Guidelines are presented to assist in the choice of code. These guidelines are accompanied by case studies that demonstrate the scenarios in which the different models might be used. At one end of the spectrum, the simpler models can be used to optimise squeeze treatments in quite complicated systems, provided good fluid flow data are available, and it is known that the assumptions made are valid. At the other extreme, cases are presented that show the application of field models in investigating issues such as the impact on squeeze life of formation cooling due to the preflush, the placement of polymer gel diverters in crossflowing horizontal wells, and the impact of such diverters on the subsequent inhibitor placement.
Typical recommendations stemming from these studies are discussed. For example, partitioning of fluid flow during injection and production is shown to be one of the most important factors in determining the effectiveness of squeeze treatments in horizontal wells with strong crossflow. Thus there is a need to obtain accurate production logging data to determine the effectiveness of diverter treatments in such wells.
Horizontal Gravel Packing Successfully Moved to Deepwater Floating Rig Environment
Authors: Mathis Stephen P. , Costa Luiz A. G. , de Sa Andrea N. , Tsuha Heitor , Calderon Agostinho , Arango Juan Carlos , MacDonald Ken , Hebert Scott A. 
Published: December 2007

Abstract
This paper demonstrates the successful application of horizontal gravel packing in the deepwater, subsea, floating-rig environment of Petrobras' Marlim field, offshore Brazil. The three gravel packs described in this paper were the first of their kind to be placed in water depths exceeding 2,500 ft (760 m) from a floating rig. The use of 13 chrome material screens require all acid treatments performed upon initial completion and during the life of the well to be well planned.
Based on the experience gained from the Marlim wells, this paper will present guidelines for drilling the reservoir section, preparing the open hole and placing the gravel. Since one of these wells is an injector, we will also present guidelines for preparing a horizontal gravel pack for water injection.
Among specific operational parameters and results we will discuss are precise gravel placement with close control over the pumping process. In addition, the gravel volumes placed demonstrate complete annular packing even in the presence of borehole washouts. As extensive in-house and industry-wide testing confirms, the use of extended-longevity well screens provided mechanical robustness and plugging resistance. We will also address the drill-in fluid and its role in preventing formation damage while depositing a filter cake that remains in place during gravel packing and then cleans up with production.
Finally, we will review performance results (such as returns and initial productivity index for each well) indicating the viability of horizontal gravel packing in all deepwater environments.